EXHIBIT 99.3
                                                                    ------------


MANAGEMENT'S DISCUSSION AND ANALYSIS

Management's discussion and analysis ("MD&A") should be read in conjunction with
the audited consolidated financial statements for the year ended December 31,
2004, and the audited consolidated financial statements and MD&A for the year
ended December 31, 2003, and MD&A for the three quarters ended March 31, 2004,
June 30, 2004, and September 30, 2004.

This MD&A was written on February 23, 2005.

Management uses cash flow (before changes in non-cash working capital) to
analyze operating performance and leverage. Cash flow as presented does not have
any standardized meaning prescribed by Canadian generally accepted accounting
principles, ("GAAP") and therefore it may not be comparable with the calculation
of similar measures for other entities. Cash flow as presented is not intended
to represent operating cash flow or operating profits for the period nor should
it be viewed as an alternative to cash flow from operating activities, net
earnings or other measures of financial performance calculated in accordance
with Canadian GAAP. All references to cash flow throughout this MD&A are based
on cash flow before changes in non-cash working capital.

Management uses certain key performance indicators ("KPI's") and industry
benchmarks such as operating netbacks ("netbacks"), total capitalization and
payout ratios to analyze financial and operating performance. These KPI's and
benchmarks as presented do not have any standardized meaning prescribed by
Canadian GAAP and therefore may not be comparable with the calculation of
similar measures for other entities.

This discussion and analysis contains forward-looking statements relating to
future events or future performance. In some cases, forward-looking statements
can be identified by terminology such as "may", "will", "should", "expects",
"projects", "plans", "anticipates" and similar expressions. These statements
represent management's expectations or beliefs concerning, among other things,
future operating results and various components thereof or the economic
performance of ARC Energy Trust ("ARC" or the "Trust"). The projections,
estimates and beliefs contained in such forward-looking statements necessarily
involve known and unknown risks and uncertainties, including the business risks
discussed in the MD&A as at and for the year ended December 31, 2004, which may
cause actual performance and financial results in future periods to differ
materially from any projections of future performance or results expressed or
implied by such forward-looking statements. Accordingly, readers are cautioned
that events or circumstances could cause results to differ materially from those
predicted.

The Trust implemented new accounting policies in 2004 pursuant to requirements
of the Canadian Institute of Chartered Accountants ("CICA"). The 2004 reported
results were impacted as a result of differing presentation and disclosure under
the new policies and instruments. In addition, certain amounts presented for
comparative purposes have been restated as a result of the retroactive
application of these new policies and instruments. See "Impact of New Accounting
Policies" in this MD&A and Note 3 of the consolidated financial statements for a
detailed description of the impact on reported results.


HIGHLIGHTS

(CDN$ millions, except per unit and volume data)     2004      2003    % Change
--------------------------------------------------------------------------------
Cash flow from operations (1)                       448.0     396.2          13
Cash flow from operations per unit (1)               2.45      2.61          (6)
Net income before taxes (2)                         215.6       191          13
Net income                                          241.7     284.6         (15)
Distributions per unit                               1.80      1.80          --
Payout ratio per cent (3)                              74        71           4
Daily production (boe/d) (4)                       56,870    54,335           5
--------------------------------------------------------------------------------

(1) Before changes in non-cash working capital.

(2) Represents net income after non-controlling interest and before the future
    income tax recovery.

(3) Based on cash distributions divided by cash flow from operations before
    changes in non-cash working capital.

(4) Reported production amount is based on company interest before royalty
    burdens.

o  Unitholders of the Trust realized an annual total return of 35.8 per cent in
   2004. The Trust unit price increased 21 per cent in 2004 from $14.74 per
   trust unit to $17.90 per trust unit and the Trust paid distributions of $1.80
   per trust unit. The trust unit price responded to normal market conditions
   including exceptionally strong commodity prices.

o  Production averaged 56,870 boe per day in 2004 compared to 54,335 boe in
   2003. Production was above forecast due to incremental production from ARC's
   internal development program. Capital expenditures of $193.8 million were
   devoted to the 2004 development program and resulted in incremental
   production that offset natural production declines on existing properties.
   With ongoing internal development and optimization activities and the largest
   development capital program in the Trust's history, production volumes for
   2005 are expected to average approximately 54,800 boe per day. Production for
   the three months ended December 31, 2004 averaged 56,179 boe per day. Capital
   expenditures of $47.7 million were committed to ARC's internal development
   program during the fourth quarter of 2004.

<PAGE>
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--------------------------------------------------------------------------------

o  ARC realized record cash flow of $448 million in 2004 and declared cash
   distributions of $330 million, resulting in a 2004 payout ratio of 74 per
   cent. The remaining $118 million of 2004 cash flow was used to fund $110.8
   million of the 2004 capital expenditures and a $7.2 million contribution to
   the reclamation fund (inclusive of $1.2 million in interest income). ARC
   realized cash flow of $106.9 million for the three months ended December 31,
   2004, an increase of 19.3 per cent over the fourth quarter of 2003. The Trust
   declared cash distributions of $83.5 million ($0.45 per unit) for the three
   months ended December 31, 2004.

o  Earnings achieved in 2004 remained relatively constant as a percentage of
   cash flow compared to 2003. In 2004 the Trust's earnings of $241.7 million
   represented 54 per cent of cash flow. In 2003 earnings of $218.5 million,
   prior to a one time future income tax recovery of $66.1 million, represented
   55 per cent of cash flow.

o  During 2004 the West Texas Intermediate ("WTI") oil price reached an all time
   high price of US$55.17 per barrel and closed the year at US$43.45 per barrel.
   This increase in U.S. oil prices was partially offset by an increase in
   USD/CAD exchange rate that averaged the year at approximately $0.77 and ended
   the year at $0.83. The strength of oil prices throughout 2004 contributed to
   the record annual cash flow of $448 million. The Trust's hedging program
   offset some of the positive impact of historic high oil prices throughout the
   year as the Trust's oil hedges on approximately 50 per cent of production
   were locked in at lower prices for the majority of 2004.

o  The AECO monthly natural gas price index traded in the $5.50 per mcf to $7.50
   per mcf range during most of 2004 with the only exception in the month of
   November when the monthly index increased to $8.00 per mcf, in line with the
   increase in oil prices.

o  In response to the current and anticipated future commodity price
   environment, the Trust has adjusted its hedging strategy. The Trust's risk
   management strategy is to manage the downside risk associated with volatility
   in commodity prices, which impact both cash flow and potentially cash
   distributions. The revised strategy focuses on managing the downside risk
   while allowing more participation in commodity price increases by the use of
   "floors" or "puts". Previously, the Trust focused on protection of the
   downside risk by giving up some or all of the upside potential in the event
   of commodity price increases. At December 31, 2004, the Trust had 41 per cent
   of its 2005 production hedged at average prices, net of premiums for the cost
   of the floors, of US$38 per barrel for crude oil and $6.90 per mcf for
   natural gas. The Trust, under its revised hedging strategy, has retained
   approximately 85 per cent of the upside on forecast production for 2005.

o  The Trust's balance sheet strengthened in 2004 as the Trust's net debt to
   annual cash flow ratio declined to 0.6 times as at December 31, 2004. The
   strength in the balance sheet was attributed to the strong commodity prices
   during 2004 that enabled the Trust to fund 57 per cent of its 2004 capital
   expenditure program with cash flow rather than debt, and the fact the
   strengthening Canadian dollar decreased the Canadian equivalent of the
   Trust's long-term US$ debt by $21.9 million in 2004.

o  The Trust continues to closely monitor both operating and general and
   administrative ("G&A") expenses. Operating costs declined to $6.71 per boe in
   2004 from $7.10 per boe in 2003 primarily due to the disposition of high-cost
   properties and cost reductions achieved by the operations group. Cash G&A
   costs increased in 2004 to $1.03 per boe in 2004 versus $0.96 in 2003 in
   response to industry-wide cost pressure on cash compensation. In addition,
   the Trust incurred non-cash expenses of $8.1 million ($0.39 per boe). The
   increase in non-cash G&A expenses in 2004 was due to the implementation of a
   new long-term stock based incentive plan in 2004 and non-cash expense
   associated with the Trust Unit Rights Incentive Plan.

o  The Trust's foreign ownership levels as at December 31, stood at
   approximately 25 per cent. The Federal Government has not proceeded with
   proposed legislation introduced as part of its March 2004 budget that would
   have resulted in the loss of mutual fund status for any trust whose foreign
   ownership levels exceeded 50 per cent, which in turn would have impaired the
   tax efficiency of the trust structure. In December 2004, the Minister of
   Finance shelved the proposed legislation until further consultation with the
   industry has occurred. It is uncertain as to whether the legislation will be
   redrafted and brought forward in a new format in the future or if the
   legislation will be permanently shelved. As a result of the proposed
   legislation, a select few trusts had reorganized, or proposed to reorganize,
   their units into a dual class structure with the objective of restricting
   foreign ownership to less than 50 per cent in order to retain their status as
   a mutual fund trust in the event that the proposed legislation is enacted.
   ARC will continue to monitor these developments and if it is deemed
   appropriate, amend its capital structure as necessary to maintain the
   integrity of its structure.

CASH FLOW FROM OPERATIONS

Cash flow from operations increased by 13 per cent in 2004 to $448 million from
$396.2 million in 2003. The increase in 2004 cash flow from operations was
primarily the result of higher commodity prices together with higher production
volumes. Despite the 13 per cent increase in cash flow from operations in 2004,
the per unit cash flow from operations decreased six per cent to $2.45 per trust
unit from $2.61 per trust unit in 2003. On average there were 21 per cent more
trust units outstanding in 2004 than in 2003, which contributed to the reduction
in per unit cash flow from operations. The 2004 cash flow from operations
included a cash loss of $86.9 million on commodity and foreign currency
contracts, while 2003 cash flow included a loss of $20.3 million on commodity
and foreign currency contracts,

<PAGE>
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The following is a summary of variances in cash flow from operations from 2003
to 2004:

<TABLE>
<CAPTION>
                                          $  MILLIONS   $ PER TRUST UNIT  % VARIANCE
<C>                                          <C>               <C>               <C>
2003 Cash flow from operations               $  396.2          $   2.61           --
------------------------------------------------------------------------------------
Volume variance                                  37.6              0.25            9
Price variance                                  105.1              0.69           27
Cash losses on commodity and
     foreign currency contracts (1)             (66.6)            (0.44)         (17)
Royalties                                       (26.1)            (0.17)          (7)
Expenses:
     Transportation                              (2.8)            (0.02)          (1)
     Operating                                    1.0              0.01            1
     Cash G&A                                    (2.3)            (0.02)          (1)
     Interest                                     5.2              0.03            1
     Taxes                                       (1.0)            (0.01)          --
     Realized foreign exchange gain (loss)        2.3              0.02            1
Other                                            (0.6)               --           --
Weighted average trust units                       --             (0.50)          --
2004 Cash flow from operations               $  448.0          $   2.45           13
------------------------------------------------------------------------------------
</TABLE>

(1) Represents cash losses on commodity and foreign currency contracts including
    cash settlements on termination of commodity and foreign currency contracts.

PRODUCTION

Production volumes averaged 56,870 boe per day in 2004 compared to 54,335 boe
per day in 2003. The five per cent increase in 2004 production compared to 2003
resulted from a full year of production from the Star Oil &Gas Ltd. ("Star")
properties that were acquired in April 2003, the net impact of non-core property
dispositions, and positive results of the Trust's 2004 drilling program. The
incremental production from the development program served to offset the natural
production declines on existing properties.

PRODUCTION                              2004              2003         % CHANGE
--------------------------------------------------------------------------------
Crude oil (bbl/d)                     22,961            22,886               --
Natural gas (mcf/d)                  178,309           164,180                9
NGL (bbl/d)                            4,191             4,086                3
Total production (boe/d) (1)          56,870            54,335                5
--------------------------------------------------------------------------------
% Natural gas production                  52                50
% Crude oil and liquids production        48                50
--------------------------------------------------------------------------------

(1) Reported production for a period may include minor adjustments from previous
    production periods.

Natural gas production increased to 178.3 mmcf per day in 2004, a nine per cent
increase compared to 2003 natural gas production of 164.2 mmcf per day. The
increase was due primarily to a full year of natural gas production from the
Star acquisition that closed in the second quarter of 2003. The Trust's 2004
percentage natural gas production increased slightly to 52 per cent from 50 per
cent in 2003. The increase in the gas weighting of the Trust's production
portfolio is the result of the Star acquisition that was more heavily weighted
to natural gas production.

Oil production remained relatively consistent between 2004 and 2003 as new
production from ARC's development program offset production declines on existing
oil properties.

During the year the Trust drilled 194 gross wells (165 net wells) on operated
properties; 47 gross oil wells (42 net) and 145 gross natural gas wells (121
net), most of which were shallow gas wells, and two dry holes for a total
success rate of 99 per cent in 2004. Of the wells drilled in the year,
approximately 25 wells were not tied in as of December 31, 2004, but are
expected to be tied in during the first quarter of 2005.

In May 2004, ARC disposed of its Sundre properties in the Central Alberta area
and a number of other minor properties. The disposed properties accounted for
production of approximately 1,800 boe per day and proved plus probable reserves
of 9,244 mboe. On June 8, 2004, the Trust acquired additional producing
properties pursuant to the United Prestville corporate acquisition ("United
Prestville"). Daily production from the acquired United Prestville properties
was approximately 400 boe per day. On December 31, 2004, the Trust acquired
additional production. Due to pursuant to the Harrington & Bibler corporate
acquisition ("Harrington & Bibler") with approximately 720 boe per day of
production. Due to the December 31, 2004 closing date of the Harrington & Bibler
acquisition, 2004 production did not include any production from the newly
acquired properties.

<PAGE>
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--------------------------------------------------------------------------------

The following table summarizes the Trust's production by core area for 2004 and
2003:

<TABLE>
<CAPTION>
                                                         2004                                        2003
-----------------------------------------------------------------------------------------------------------------------
CORE AREA (1)                           TOTAL      OIL        GAS       NGL      TOTAL        OIL       GAS        NGL
-----------------------------------------------------------------------------------------------------------------------
                                       (boe/d) (bbls/d)   (mmcf/d)  (bbls/d)     (boe/d)   (bbls/d)  (mmcf/d)  (bbls/d)
<S>                                     <C>       <C>        <C>      <C>         <C>        <C>        <C>      <C>
Central AB                              9,295     2,003      32.6     1,856       9,916      2,540      32.7     1,934
Northern AB & BC                       19,026     5,733      71.1     1,441      17,556      5,449      64.4     1,374
Pembina                                 7,433     3,742      17.5       772       7,353      3,808      17.3       655
SE AB & SW Sask.                       10,871     1,658      55.2        14      10,039      2,011      45.1        19
SE Sask.                               10,245     9,825       1.9       108       9,471      9,078       1.7       104
Total                                  56,870    22,961     178.3     4,191      54,335     22,886     161.2     4,086
-----------------------------------------------------------------------------------------------------------------------
</TABLE>

(1) Provincial references: AB is Alberta, BC is British Columbia, Sask. is
    Saskatchewan, SE is Southeast, SW is Southwest.

The Trust expects 2005 production to average approximately 54,800 boe per day.
The 2005 production estimate incorporates incremental production from the
planned $240 million capital program in 2005 in addition to 720 boe per day of
incremental production from the acquired Harrington & Bibler properties.


COMMODITY PRICES PRIOR TO HEDGING

<TABLE>
<CAPTION>
BENCHMARK PRICES                                       2004                  2003              % CHANGE
--------------------------------------------------------------------------------------------------------
<S>      <C>     <C>                                   <C>                   <C>                      <C>
AECO gas ($/mcf) (1)                                   6.79                  6.67                     2
WTI oil (US$/bbl) (2)                                 41.43                 31.06                    33
USD/CAD foreign exchange rate                          0.77                  0.71                     8
WTI oil (CDN$/bbl)                                    53.81                 43.57                    24
--------------------------------------------------------------------------------------------------------
</TABLE>

(1)  Represents the AECO monthly posting.
(2)  WTI represents West Texas Intermediate posting as denominated in US$.

The Canadian denominated oil price received by ARC and other Canadian energy
companies was negatively impacted by the continued strength of the Canadian
dollar with respect to the U.S. dollar during 2004. While crude oil prices
reached a historic high of US$55.17 per barrel in 2004, the Canadian dollar also
reached a 12 year high of US$0.85 in 2004. The strength of the Canadian dollar
served to partially offset the impact of higher U.S. dollar denominated oil
prices. Despite the 33 per cent increase in the US$ WTI oil price in 2004,
relative to 2003, the Canadian dollar denominated oil price increased by only 24
per cent to $53.81 per barrel in 2004 compared to $43.57 per barrel in 2003. The
Trust's realized oil price, before hedging, increased by 23 per cent to $47.03
per barrel in 2004 compared to $38.15 per barrel in 2003. The Trust's oil
production consists predominantly of light and medium crude oil while heavy oil
accounts for approximately five per cent of the Trust's liquids production.

The differential between the Edmonton posted price and field price widened in
the fourth quarter of 2004. The average quality and transportation differential
on the Trust's oil production was approximately $5.50 per barrel in the first
nine months of 2004 and increased to $8.20 in the fourth quarter of 2004. The
widening differential was due to a global oversupply of heavy oil and sour crude
production into the market, which contributed to lower realized oil prices in
the fourth quarter.

Alberta AECO Hub prices averaged $6.79 per mcf in 2004 compared to $6.67 per mcf
in 2003. ARC's realized gas price, before hedging, increased by four per cent to
$6.78 per mcf compared to $6.49 per mcf in 2003. ARC's realized gas price is
based on prices received at the various markets in which the Trust sells its
natural gas. ARC's natural gas sales portfolio consists of gas sales priced at
the AECO monthly index, the AECO daily spot market, eastern and mid-west United
States markets and a portion to aggregators.

Prior to hedging activities, ARC realized $43.32 per boe in 2004, a 13 per cent
increase over the $38.27 per boe received prior to hedging in 2003. ARC's
reported price of $43.32 per boe in 2004 is not directly comparable to the
$37.47 per boe price reported in 2003 as a result of new hedge accounting
guidelines that were implemented in 2004. Under the new hedge accounting
guideline, 2004 revenue and prices are presented prior to hedging gains or
losses while 2003 revenue and prices are inclusive of realized hedging gains or
losses. See "Impact of New Accounting Policies" in this MD&A and Note 3 of the
consolidated financial statements for further discussion regarding the impact of
Hedge Accounting that was implemented in 2004.

<PAGE>
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--------------------------------------------------------------------------------

The following is a summary of realized prices in 2004 and 2003 before hedging
activities:

ARC REALIZED PRICES (1) (2)                          2004      2003     % CHANGE
--------------------------------------------------------------------------------
Oil ($/bbl)                                         47.03     38.15           23
Natural gas ($/mcf)                                  6.78      6.49            4
NGL's ($/bbl)                                       39.04     32.19           21
Total commodity revenue before hedging ($/boe)      43.13     38.09           13
--------------------------------------------------------------------------------

(1) 2004 revenue and prices as reported above are prior to gains and losses on
    commodity and foreign currency contracts. All gains and losses on 2004
    contracts are included in "loss on commodity and foreign currency contracts"
    in the statement of income as these contracts have not been designated as
    accounting hedges. 2003 reported prices are net of hedging gains and losses.
(2) 2003 prices have been reclassified to reflect prices prior to transportation
    costs.

The Trust has entered into foreign currency hedging contracts to minimize the
impact that fluctuations in the USD/CAD exchange rate have on cash flow (see
Note 10 of the consolidated financial statements). In addition, the majority of
the Trust's debt and certain of the Trust's transactions are denominated in U.S.
dollars partially offsetting the negative impact of USD/CAD exchange rate
fluctuations.

Reported prices reflect field prices net of quality differentials and prior to
field transportation costs. This presentation standard was adopted in 2004.
Prices reported in 2003 have been reclassified to reflect the same presentation.
See "Impact of New Accounting Policies" in this MD&A and Note 3 of the
consolidated financial statements for further discussion of the nature and
impact of the transportation cost presentation.


REVENUE

Revenue before hedging increased to $901.8 million in 2004, an increase of 19
per cent compared to 2003 revenue before hedging of $759.1 million. Higher
production volumes and significantly higher commodity prices contributed to the
higher revenue in 2004. Revenue in 2003 included realized hedging losses of $16
million ($0.80 per boe) on commodity and foreign currency contracts. Net
realized and unrealized losses on commodity and foreign currency contracts in
2004 have been presented as a separate component of revenue in the statement of
income rather than being netted against revenue.

A breakdown of revenue is as follows:

REVENUE ($ THOUSANDS) (1) (2)                         2004       2003   % CHANGE
--------------------------------------------------------------------------------
Oil revenue                                        395,203    308,259         28
Natural gas revenue                                442,537    383,290         15
NGL's revenue                                       59,886     47,998         25
--------------------------------------------------------------------------------
Total commodity revenue                            897,626    739,547         21
Other revenue                                        4,156      3,636         14
Total revenue (2)                                  901,782    743,183         21
Total revenue before hedging (2)                   901,782    759,134         19
--------------------------------------------------------------------------------

(1) 2003 revenue has been reclassified to reflect revenue prior to
    transportation costs. Revenue and transportation costs both increased by $12
    million in 2003 as a result of the reclassification.
(2) Revenue for 2003 includes cash hedging losses of $21.7 million and non-cash
    hedging gains of $5.7 million. There are no hedging gains or losses in the
    reported 2004 revenue amounts. Gains and losses on commodity and foreign
    currency contracts in 2004 have been reported separately in the statement of
    income.

RISK MANAGEMENT AND HEDGING ACTIVITIES

The Trust's hedging activities are conducted by an internal Risk Management
Committee, based upon guidelines approved by the Board, which has the following
objectives as its mandate:

o  protect unitholder return on investment;

o  provide for minimum monthly cash distributions to unitholders;

o  employ a portfolio approach to hedging by entering into a number of small
   positions that build upon each other; o participate in commodity price
   upturns to the greatest extent possible while limiting exposure to price
   downturns; and,

o  ensure profitability of specific oil and gas properties that are more
   sensitive to changes in market conditions.

The Trust uses both options and swaps to manage exposure to fluctuations in
commodity prices, foreign exchange rates and interest rates. The Trust considers
these contracts to be effective economic hedges as they meet the objectives of
the Trust's risk management mandate.

In response to the current commodity price environment, the Trust has updated
its hedging strategy. Previously, the Trust's hedging portfolio consisted of a
large number of costless transactions that mitigated the risk associated with
downturns in commodity prices while limiting the Trust's upside participation in
a rising price environment. The Trust's current strategy is to focus on price
floor (put) structures that limit the Trust's exposure to downturns in commodity
prices while allowing participation in commodity price increases.

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--------------------------------------------------------------------------------

During the fourth quarter, the Trust terminated certain crude oil and foreign
currency contracts in response to its revised hedging strategy. The Trust paid
$4.9 million to terminate certain contracts, consisting of a net payment (loss)
of $29.4 million for the crude oil contracts and a net receipt (gain) of $24.5
million for the foreign currency contracts. Immediately following the
termination of the contracts, the Trust entered into new crude oil floors and
foreign currency swaps in accordance with its new hedging strategy. By
terminating existing contracts and entering into the new contracts, the Trust
was able to enter into contracts for a minimum specified price while maintaining
the upside on most of the Trust's production. The $4.9 million paid by the Trust
on termination has been recorded as a reduction of cash flow from operations in
the fourth quarter.

The Trust's commodity and foreign currency hedging transactions are undertaken
with financially sound, credit worthy counterparties, to reduce exposure to
credit risk. All contracts require approval of the Trust's Risk Management
Committee prior to execution.

The following is a summary of contracts in place as at December 31, 2004. Refer
to Note 10 of the consolidated financial statements for complete details of
contracts in place at December 31, 2004.

<TABLE>
<CAPTION>
                                              2005                                            2006 AND BEYOND (3)
-------------------------------------------------------------------------------------------------------------------------
                                                                        PERCENTAGE
                                                                            UPSIDE
                                                         CONTRACT         RETAINED
                                                       PRICES NET            ABOVE
                                  CONTRACT            OF PREMIUMS         CONTRACT          CONTRACT            CONTRACT
                                VOLUME (2)            PRICE $ (1)        PRICE (1)        VOLUME (2)           PRICE (1)
-------------------------------------------------------------------------------------------------------------------------
<S>                       <C>                     <C>                          <C>   <C>                 <C>
Oil (bbl/d)                         13,000           US$38.06/bbl              83%               992        US$40.27/bbl
Natural gas (mcf/d)                 58,041            CDN$6.90/GJ              87%                --                  --
-------------------------------------------------------------------------------------------------------------------------
Total boe/d (2)                     22,674           US$35.67/boe              85%               992        US$40.27/boe
Total boe (3)                    8,277,093           US$35.67/boe              85%           181,000        US$40.27/boe
AECO/NYMEX basis (mcf/d)             5,863           US$0.865/mcf               --                --                  --
Foreign currency
   (sell US$) (4)         US$146.7 Million               CDN$1.21               --     US$13 Million            CDN$1.21
Electricity (MW/h)                       5                 $63.00               --                 5              $63.00
Interest rates (5)         US$62.5 Million        LIBOR+38.25 bps               --   US$62.5 Million     LIBOR+38.25 bps
-------------------------------------------------------------------------------------------------------------------------
</TABLE>

(1) Oil prices, AECO basis and total boe prices are in US$; natural gas, foreign
    currency and electricity are in CDN$. Prices represent average prices as of
    December 31, 2004. Average hedged prices are net of premiums and are
    calculated with reference to futures pricing at year end, detailed contract
    prices are contained in Note 10 of the financial statements.

(2) Volumes represent average daily volume for oil, natural gas and electricity
    transactions for the entire period.

(3) The amounts presented for the remaining contract period represent contracts
    in place for commodity contracts to June 2006, for electricity until 2010
    and for interest rate hedges until 2014.

(4) Total contract volume for foreign currency contracts represents the net USD
    notional amount for the respective term.

(5) A fixed interest rate of 4.62 per cent has been swapped to a floating rate
    of LIBOR plus 38.25 basis points.

For 2004 the Trust had contracts in place for approximately 64 per cent of
liquids production and 37 per cent of natural gas production resulting in
approximately 49 per cent of production being hedged. As at December 31, 2004,
the Trust had approximately 41 per cent of total 2005 production hedged with 49
per cent of liquids production hedged (13,000 bbls per day) at a net average
price of US$38.06 per bbl and approximately 34 per cent of natural gas
production (61,233 GJ per day) is hedged at an average price of $6.54 per GJ.
Average prices are net of hedging premiums and are calculated with reference to
futures pricing at year end. The Trust is committed to pay $29.4 million of
premiums relating to put contracts entered into for 2005. The premiums on the
put contracts will be recorded as a realized hedge loss when payment is made in
a future period. The Trust's oil contracts are based on the WTI index and the
majority of the Trust's natural gas contracts are based on the AECO monthly
index.

The table below illustrates ARC's average hedged price, total corporate price in
2005 and commodity hedge gains and losses as a result of the Trust's 2005
commodity hedging program in place as of December 31, 2004, at various commodity
prices. The foreign exchange table illustrates the gains and losses pursuant to
the Trust's foreign exchange hedges at various USD/CAD exchange rates.

<PAGE>
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--------------------------------------------------------------------------------

<TABLE>
<CAPTION>
--------------------------------------------------------------------------------------------------------------------------
                                                                            2005 COMMODITY PRICE AND
IMPACT OF 2005 HEDGING                                                  FOREIGN EXCHANGE RATE ASSUMPTIONS
--------------------------------------------------------------------------------------------------------------------------
<S>                                                     <C>                <C>                <C>               <C>
Oil
Oil price per barrel (US$/WTI)                          $   30.00          $  40.00           $ 50.00           $   60.00
ARC's average hedged price (US$/barrel) (1)                 37.28             37.97             39.95               46.30
Average price on forecasted volumes (US$/WTI) (1)           33.56             39.01             45.09               53.31
Oil hedging gains (losses) (CDN$ millions) (2)               34.3              (9.2)              (47)                (73)
--------------------------------------------------------------------------------------------------------------------------

Natural Gas
Natural gas price per gigajoule (CDN$/GJ)               $    6.00          $   7.00           $  8.00           $    9.00
ARC's average hedged price (CDN$/GJ)                         6.43              6.77              7.56                8.25
Average price on forecasted volumes (CDN$/GJ)                6.16              6.93              7.85                8.74
Natural gas hedging gains (losses) (CDN$ millions)           14.9               2.8             (7.2)              (15.6)
--------------------------------------------------------------------------------------------------------------------------

Foreign Exchange
Foreign exchange rate (USD/CAD)                         $    0.78          $   0.80           $  0.82           $    0.84
Foreign exchange hedge gains (losses) (CDN$ millions)      (10.3)             (5.6)             (1.1)                 3.1
--------------------------------------------------------------------------------------------------------------------------
</TABLE>

(1) Incorporates the impact of hedging premiums.
(2) Based on foreign exchange rate assumption of CDN/US$0.80.


GAIN OR LOSS ON COMMODITY AND FOREIGN CURRENCY CONTRACTS

Gain or loss on commodity and foreign currency contracts comprise realized and
unrealized gains or losses on commodity and foreign currency contracts that do
not meet the requirements of an effective accounting hedge, even though the
Trust considers all commodity and foreign currency contracts to be effective
economic hedges. Accordingly, gains and losses on such contracts are shown as a
separate expense in the statement of income.

The Trust recorded a loss on commodity and foreign currency contracts of $86.1
million in 2004, consisting of an unrealized fair value loss of $4 million and a
realized loss of $82 million.

The following is a summary of the gain (loss) on commodity and foreign currency
contracts for 2004:

<TABLE>
<CAPTION>
Commodity and Foreign Currency Contracts
                                                             CRUDE OIL &     NATURAL    FOREIGN       2004       2003
($ THOUSANDS)                                                    LIQUIDS         GAS   CURRENCY      TOTAL      TOTAL
----------------------------------------------------------------------------------------------------------------------
<S>                                                             <C>           <C>        <C>       <C>        <C>
Realized cash (loss) gain
     on contracts (1)                                           (109,558)     (6,457)    29,106    (86,909)   (21,653)
Non-cash gain on contracts (2)                                        --       3,508      1,375      4,883      5,702
Non-cash amortization of opening deferred
     hedge (loss) gain (3)                                       (15,974)     (3,894)     5,293    (14,575)        --
Unrealized (loss) gain on contracts,
     change in fair value (4)                                     (4,749)     18,764     (3,482)    10,533         --
----------------------------------------------------------------------------------------------------------------------
Total gain (loss) on commodity and
     foreign currency contracts                                 (130,281)     11,921     32,292    (86,068)   (15,951)
----------------------------------------------------------------------------------------------------------------------
</TABLE>

(1) Realized cash gains and losses represent actual cash settlements or receipts
    under the respective contracts.

(2) Non-cash gains of $4.9 million and $5.7 million for 2004 and 2003,
    respectively, represent non-cash amortization of deferred commodity and
    foreign currency contracts.

(3) Represents non-cash amortization of the opening deferred hedge loss of $14.6
    million to income over the terms of the contracts in place at January 1,
    2004. The opening deferred hedge loss has been fully amortized at December
    31, 2004.

(4) The unrealized loss on contracts represents the change in fair value of the
    contracts during the period. The fair value of the contracts was a loss of
    $14.6 million at January 1, 2004 and a loss of $4 million at December 31,
    2004.

The 2004 $86.1 million loss on commodity and foreign currency contracts
consisted of a realized (cash) loss of $86.9 million, an unrealized (non-cash)
fair value loss of $4 million, and a non-cash gain of $4.9 million.

The unrealized loss on commodity and foreign currency contracts reflects the
change in the fair value of commodity and foreign exchange contracts during each
reporting period. To the end of the third quarter of 2004, the Trust had
recorded an unrealized fair value loss of $63.6 million on commodity and foreign
currency contracts. During the fourth quarter of 2004, the Trust recorded an
unrealized gain of $59.6 million on commodity and foreign currency contracts to
arrive at a net year-to-date loss of $4 million. The significant unrealized gain
recorded in the fourth quarter was attributed to the termination of existing
contracts and entering into new contracts at higher effective hedged prices. At
the same time, the decrease in forward prices from September 30, 2004, to
December 31, 2004, also contributed to the unrealized gain in the fourth
quarter. In 2003 there were no unrealized gains or losses on commodity and
foreign currency contracts, as all contracts were deemed to be effective
accounting hedges up to December 31, 2003.

<PAGE>
Page 8
--------------------------------------------------------------------------------

OPERATING NETBACKS

The Trust's operating netback, after realized hedging losses, increased six per
cent to $23.46 per boe in 2004 compared to $22.16 per boe in 2003. The increase
in netbacks in 2004 is due primarily to higher realized prices partially offset
by increased hedging losses.

The netbacks incorporate realized losses on commodity and foreign currency
contracts of $3.94 per boe for 2004, compared to losses of $0.80 per boe in
2003. Fair value loss on commodity and foreign currency contracts of $4 million
in 2004 were not recorded as a reduction of the netback.

The components of operating netbacks are shown below:

<TABLE>
<CAPTION>
                                                                                                        2004         2003
NETBACK                                                            OIL         GAS        NGL          TOTAL        TOTAL
--------------------------------------------------------------------------------------------------------------------------
                                                                ($/bbl)     ($/mcf)    ($/bbl)        ($/boe)      ($/boe)
<S>                                                               <C>          <C>      <C>            <C>          <C>
Weighted average sales price (1)                                  47.03        6.78     39.04          43.13        38.09
Other revenue                                                        --          --        --           0.19         0.18
--------------------------------------------------------------------------------------------------------------------------
Total revenue                                                     47.03        6.78     39.04          43.32        38.27
Royalties                                                        (8.30)      (1.39)   (10.72)         (8.51)       (7.61)
Transportation (1)                                               (0.19)      (0.20)        --         (0.71)       (0.60)
Operating costs (3)                                              (8.46)      (0.93)    (5.28)         (6.71)       (7.10)
--------------------------------------------------------------------------------------------------------------------------
Netback prior to hedging                                          30.08        4.26     23.04          27.39        22.96
Loss on commodity and foreign
     currency contracts (2)                                      (9.41)      (0.05)        --         (3.94)       (0.80)
--------------------------------------------------------------------------------------------------------------------------
Netback after hedging                                             20.67        4.21     23.04          23.45        22.16
--------------------------------------------------------------------------------------------------------------------------
</TABLE>

(1) 2003 revenue and transportation costs have been reclassified to reflect
    revenue prior to transportation costs. Previously, revenue was presented net
    of transportation cost. This reclassification did not impact the netback.

(2) Excludes unrealized fair value loss on commodity and foreign currency
    contracts of $4 million in 2004 (nil in 2003).

(3) Operating expenses are composed of direct costs incurred to operate both oil
    and gas wells. A number of assumptions have been made in allocating these
    costs between oil, natural gas and natural gas liquids production.

Royalties increased to $8.51 per boe in 2004 compared to $7.61 per boe in 2003.
Royalties are calculated and paid based on commodity revenue net of associated
transportation costs and before any commodity hedging gains or losses. Royalties
as a percentage of pre-hedged commodity revenue net of transportation costs
remained unchanged at 20 per cent.

Operating costs, net of processing income, remained relatively consistent at
$139.7 million in 2004 compared to $140.7 million in 2003. Operating costs per
boe decreased five per cent to $6.71 per boe in 2004 compared to $7.10 per boe
in 2003. Despite higher average production in 2004, total operating costs
remained relatively constant as a result of two property divestitures, one in
the third quarter of 2003 and one in the second quarter of 2004, which carried
higher proportionate operating costs per boe. The increased natural gas
weighting of the Trust's 2004 production also served to reduce operating costs
in total and per boe as natural gas production typically incurs a lower
operating cost than oil. In addition, cost adjustments on ARC's non-operated
properties for pre-2003 production periods negatively impacted the Trust's
operating costs in 2003. The cost savings realized in 2004 from higher cost
property divestitures and increased natural gas production were somewhat offset
by the impact of higher costs of services throughout the industry particularly
for service rigs, trucking costs and mechanical services.

The Trust expects the trend of increasing costs to continue in 2005 as the
demand for services is expected to continue at unprecedented levels.
Consequently, ARC expects 2005 operating costs to increase slightly from 2004
levels to approximately $7.00 per boe.

Effective for 2004, ARC's transportation costs have been presented as an expense
in the statement of income, whereas previously they were recorded as a reduction
of revenue. For comparative purposes, 2003 amounts have been reclassified.
Transportation costs as presented in the statement of income are defined by the
point of legal transfer of the product. Transportation costs are dependent upon
where the product is sold, product split, location of properties, and industry
transportation rates. For the majority of ARC's gas production, legal title
transfers at the intersection of major pipelines (referred to as "the Hub")
whereas the majority of ARC's oil production is sold at the outlet to the field
oil battery. Consequently, there are higher transportation costs incurred
directly by ARC with gas production due to the distance from the wellhead to the
Hub. Transportation costs increased 18 per cent to $0.71 per boe in 2004
compared to $0.60 per boe in 2003.


GENERAL AND ADMINISTRATIVE EXPENSES AND TRUST UNIT INCENTIVE COMPENSATION

Cash general and administrative expenses ("G&A"), net of overhead recoveries on
operated properties increased to $21.4 million ($1.03 per boe) in the 2004 from
$19.1 million ($0.96 per boe) in 2003. Increases in cash G&A expenses in total
and per boe for 2004 relative to 2003 were the result of the Star acquisition
and increasing costs to manage the business associated with increased staff
levels. As well, due to unprecedented levels of activity for ARC and for the
industry as a

<PAGE>
Page 9
--------------------------------------------------------------------------------

whole in 2004, the costs associated with hiring, compensating and retaining
employees and consultants has risen. It is essential for the Trust to maintain
competitive compensation levels to ensure that we continue to attract and retain
the most qualified individuals.

A non-cash trust unit incentive compensation expense ("non-cash compensation
expense") of $8.1 million ($0.39 per boe) was recorded in 2004 compared to $3.5
million ($0.18 per boe) in 2003. This non-cash amount relates to both the Trust
Unit Incentive Rights Plan ("Rights Plan") and the Whole Trust Unit Incentive
Plan.

The $5.2 million non-cash expense for the Rights Plan was determined based upon
the prospective adoption of a fair value calculation. Only the rights that were
issued on or after January 1, 2003 are subject to valuation and expense in the
statement of income.

Previously, the Trust recorded compensation expense for the rights based on the
intrinsic value methodology, which resulted in the expense amount being based on
the underlying trust unit price at each period end. In accordance with CICA
Handbook Section 3870, an entity may apply an intrinsic value methodology if it
is impossible to estimate a fair value at grant date, and in particular, for
situations where there is a declining exercise price which is subject to
uncertainty. In the fourth quarter of 2004, the Trust adopted the fair value
methodology of valuation of the rights based on certain assumptions and
estimates. The Trust was enabled to determined fair value estimates given that
the rights plan has now been discontinued, the remaining vesting period of
rights is more determinable and there is more predictability regarding future
distributions and future reductions in the rights exercise price. As the change
in methodology qualifies as a change in estimate under accounting standards, the
fair value methodology has been applied prospectively without restatement of
prior periods.

The Trust has estimated the fair value of the rights issued in 2003 and 2004
based on the following assumptions and estimates:

                                                                           2004
--------------------------------------------------------------------------------
Expected annual dividend                                                $  1.80
Expected annual right's exercise price reduction                        $  0.72
Expected volatility                                                       13.2%
Risk-free interest rate                                                    3.7%
Expected life of rights (years)                                             1.1
Expected annual forfeitures (per cent)                                       --
--------------------------------------------------------------------------------

As at December 31, 2004, the fair value calculation resulted in cumulative
expense of $8.7 million compared to the $10.2 million recorded as cumulative
compensation expense to September 30, 2004, under the intrinsic value
methodology. The $1.5 million was recorded as compensation recovery in the
fourth quarter of 2004. The remaining future fair value of the rights of $3.7
million will be recognized in earnings over the remaining vesting period of the
rights outstanding.

In March 2004 the Board of Directors upon recommendation by the Compensation
Committee, approved a new Whole Unit Plan to replace the existing Rights Plan
for new awards granted subsequent to the first quarter of 2004. The new Whole
Unit Plan will result in employees, officers and directors (the "plan
participants") receiving cash compensation in relation to the value of a
specified number of underlying trust units. The Whole Unit Plan consists of
Restricted Trust Units ("RTU's") for which the number of trust units is fixed
and that will vest over a period of three years and Performance Trust Units
("PTU's") for which the number of trust units is variable and will vest at the
end of three years. The Trust issued 226,837 RTU's and 128,908 PTU's to
employees, officers and directors in 2004, of which 2,439 RTU's and 577 PTU's
were subsequently forfeited in 2004. Upon vesting, the plan participant is
entitled to receive a cash payment based on the fair value of the underlying
trust units plus accrued distributions. The cash compensation issued upon
vesting of the PTU's is dependent upon the future performance of the Trust
compared to its peers based on certain key industry benchmarks. The value
associated with the RTU's and PTU's will be expensed in the statement of income
over the vesting period with the expense amount being determined by the trust
unit price, the number of PTU's to be issued on vesting, and distributions.
Therefore, the expense recorded in the statement of income may fluctuate over
time. The $1.9 million ($0.14 per boe) non-cash expense attributed to the new
Whole Unit Plan is based on 352,729 committed trust units under the Whole Unit
Plan as at December 31, 2004. The 2004 expense consists of a short-term portion
of $1 million and a long-term portion of $1.9 million. Under the new Whole Unit
Plan, a non-cash expense will be recorded each period in the statement of
income. A realization of the expense and a resulting reduction in cash flow will
occur each year when a cash payment is made upon vesting in the second quarter
of each year. The Whole Unit Plan expense does not impact cash flow until a cash
payment is made.

<PAGE>
Page 10
--------------------------------------------------------------------------------

The following is a breakdown of G&A and trust unit incentive compensation
expense:

<TABLE>
<CAPTION>
G&A AND TRUST UNIT INCENTIVE COMPENSATION EXPENSE
($ THOUSANDS EXCEPT PER BOE)                                                     2004              2003         % CHANGE
-------------------------------------------------------------------------------------------------------------------------
<S>                                                                            <C>               <C>                  <C>
G&A expenses                                                                   30,733            25,346               21
Operating recoveries                                                           (9,307)           (6,250)              49
-------------------------------------------------------------------------------------------------------------------------
Cash G&A expenses                                                              21,426            19,096               12
Non-cash compensation-- Rights Plan                                             5,171             3,470               49
Accrued cash compensation-- Whole Unit Plan                                     2,915                --               --
-------------------------------------------------------------------------------------------------------------------------
Total G&A and trust unit incentive
     compensation expense                                                      29,512            22,566               31
-------------------------------------------------------------------------------------------------------------------------
Cash G&A expenses per boe                                                        1.03              0.96                7
Total G&A and trust unit incentive
     compensation expense per boe                                                1.42              1.14               25
-------------------------------------------------------------------------------------------------------------------------
</TABLE>

The Trust expects 2005 G&A costs, excluding non-cash G&A associated with the
Trust's Rights Plan and Whole Unit Plan, to be approximately $1.25 per boe. In
addition, the Trust expects 2005 non-cash G&A of approximately $0.30 per boe for
the non-cash trust unit incentive compensation expense associated with the
Rights Plan and Whole Unit Plan. The increasing G&A costs in 2005 are the result
of higher compensation levels associated with hiring and retaining the most
qualified employees and consultants as it is expected that the robust levels of
activity will continue throughout the industry in 2005.


INTEREST EXPENSE

Interest expense decreased to $13.3 million in 2004 from $18.5 million in 2003.
The decrease in interest expense is attributed to a lower average debt balance
in 2004 compared to 2003 as a result of increased cash flow and a higher portion
of the Trust's 2004 capital program having been cash funded.

On April 27, 2004, with the issuance of US$125 million of long-term notes, the
Trust repaid all Canadian denominated debt. As at December 31, 2004, the Trust's
debt balance was almost entirely U.S.-denominated fixed rate debt with an
average rate of 4.86 per cent (3.81 per cent including the current impact of the
interest rate swap contracts) and an average life of 6.5 years. With the
issuance of the fixed rate notes and repayment of variable rate debt, the
Trust's effective interest rate, before the impact of interest rate swaps,
increased slightly.

In order to capitalize on low short-term interest rates in the United States,
the Trust entered into interest rate swap agreements to convert US$62.5 million
of fixed rate debt into floating rate debt at a rate equal to the three month
LIBOR rate plus 38.25 basis points through to 2014. The Trust realized a cash
gain of $1.4 million on the interest rate swap in 2004 and this amount has been
netted against interest expense in the statement of income. The average rate on
the interest rate swap was approximately 2.4 per cent during 2004.

The following is a summary of the debt balance and interest expense for 2004 and
2003:

<TABLE>
<CAPTION>
INTEREST EXPENSE
($ THOUSANDS)                                                                 2004               2003           % CHANGE
-------------------------------------------------------------------------------------------------------------------------
<S>                                                                        <C>                <C>                    <C>
Period end debt balance (1)                                                220,549            232,402                 (5)
     Fixed rate debt                                                       220,259             84,006                162
     Floating rate debt                                                        290            148,396               (100)
-------------------------------------------------------------------------------------------------------------------------
Interest expense before interest rate swaps (2)                             14,675             18,482                (21)
Gain on interest rate hedge                                                 (1,355)                --                 --
Net interest expense (3)                                                    13,320             18,482                (28)
-------------------------------------------------------------------------------------------------------------------------
</TABLE>

(1) Includes both long-term and current portions of debt.

(2) The interest rate swap was designated as an effective hedge for accounting
    purposes whereby actual realized gains and losses are netted against
    interest expense.

(3) 2003 interest expense excludes interest on convertible debentures.


FOREIGN EXCHANGE GAINS AND LOSSES

The Trust recorded a gain of $20.7 million ($1.00 per boe) on foreign exchange
transactions compared to a gain of $18.6 million ($0.94 per boe) in 2003. These
amounts include both realized and unrealized foreign exchange gains and losses.
Unrealized foreign exchange gains and losses are due to revaluation of U.S.
denominated debt balances. The volatility of the Canadian dollar during the
reporting period has a direct impact on the unrealized component of the foreign
exchange gain or loss. The unrealized gain/loss impacts net income but does not
impact cash flow as it is a non-cash amount. Realized foreign exchange gains or
losses arise from U.S. denominated transactions such as interest payments, debt
repayments and hedging settlements.

<PAGE>
Page 11
--------------------------------------------------------------------------------

The following is a breakdown of the total foreign exchange gain (loss):

<TABLE>
<CAPTION>
FOREIGN EXCHANGE GAIN (LOSS)
($ THOUSANDS EXCEPT PER BOE)                                                  2004               2003            % CHANGE
--------------------------------------------------------------------------------------------------------------------------
<S>                                                                         <C>                <C>                     <C>
Unrealized gain on U.S. denominated debt                                    21,923             18,700                  17
Realized (loss) on U.S. denominated
     debt repayments                                                        (3,495)                --                  --
Realized gain (loss) on U.S.
     denominated transactions                                                2,285               (136)                 --
Total foreign exchange gain                                                 20,713             18,564                  12
Total foreign exchange gain per boe                                           1.00               0.94                   6
--------------------------------------------------------------------------------------------------------------------------
</TABLE>

TAXES

Capital taxes paid or payable by ARC, based on debt and equity levels at the end
of the year, amounted to $2.8 million in 2004 compared to $1.8 million in 2003.
The increase in 2004 capital taxes was attributed to the higher taxable capital
base as a result of the Star acquisition, as well as a lower installment base
for the first quarter of 2003 due to prior year excess installments having been
made.

In 2004 a future income tax recovery of $26.1 million was included in income
compared to a $93.5 million recovery in 2003. The lower future income tax
recoveries in 2004 relative to 2003 are due to a recovery of $66.1 million being
recorded in 2003 as a result of reductions in future corporate income tax rates
that became effective in 2003. The 2004 future income tax recovery of $26.1
million includes a recovery of $5.9 million due to the change in Alberta
corporate income tax rates and the reduction in the Trust's future expected
income tax rate. The current year recovery also includes a $1.4 million recovery
due to the net derivative liability recorded on the balance sheet at December
31, 2004 pursuant to hedge accounting (nil in 2003).

In the first quarter of 2004 the Alberta government passed legislation to reduce
provincial corporate income tax rates to 11.5 per cent from 12.5 per cent
effective April 1, 2004. ARC's expected future income tax rate incorporating
this rate reduction is approximately 34 per cent (35 per cent in 2003) compared
to the current rate of approximately 39 per cent applicable to the 2004 income
tax year.

Corporate acquisitions completed in 2004 resulted in the Trust recording a
future income tax liability of $24.5 million due to the difference between the
tax basis and the fair value assigned to the acquired assets. The amount of tax
pools versus asset value is one of the parameters that impacts the Trust's
acquisition bid levels.

In the Trust's structure, payments are made between ARC Resources and the Trust,
transferring both income and future tax liability to the unitholders. At the
current time, ARC does not anticipate any cash taxes will be paid by ARC
Resources.


DEPLETION, DEPRECIATION AND ACCRETION OF ASSET RETIREMENT OBLIGATION

The depletion, depreciation and accretion ("DD&A") rate increased slightly to
$11.51 per boe in 2004 from $11.02 per boe in 2003. The higher DD&A rate is due
to the Star acquisition in the second quarter of 2003 for which the Trust
recorded a higher proportionate cost per barrel of proved reserves of the
acquired Star properties compared to the existing ARC properties. In addition,
the higher asset retirement obligation recorded in 2004 has resulted in higher
accretion expense in 2004.

A breakdown of the DD&A rate is a follows:

<TABLE>
<CAPTION>
DD&A RATE
($ THOUSANDS EXCEPT PER BOE AMOUNTS)                                          2004               2003            % CHANGE
--------------------------------------------------------------------------------------------------------------------------
<S>                                                                        <C>                <C>                       <C>
Depletion of oil & gas assets (1)                                          235,094            215,593                   9
Accretion of asset retirement obligation (2)                                 4,580              2,958                  55
--------------------------------------------------------------------------------------------------------------------------
Total DD&A                                                                 239,674            218,551                  10
DD&A Rate per boe                                                            11.51              11.02                   4
--------------------------------------------------------------------------------------------------------------------------
</TABLE>

(1) Includes depletion of the capitalized portion of the asset retirement
    obligation that was capitalized to the property, plant and equipment
    ("PP&E") balance and is being depleted over the life of the reserves.

(2) Represents the accretion expense on the asset retirement obligation during
    the period.

The costs subject to depletion included $42.3 million relating to the
capitalized portion of the asset retirement obligation as at December 31, 2004
($41.1 million as at December 31, 2003), net of accumulated depletion.

<PAGE>
Page 12
--------------------------------------------------------------------------------

GOODWILL

The goodwill balance of $157.6 million arose as a result of the acquisition of
Star in 2003. The goodwill balance was determined based on the excess of total
consideration paid, plus the future income tax liability, less the fair value of
the assets for accounting purposes acquired in the transaction.

Accounting standards require that the goodwill balance be assessed for
impairment at least annually or more frequently if events or changes in
circumstances indicate that the balance might be impaired. If such an impairment
exists, it would be charged to income in the period in which the impairment
occurs. The Trust has determined that there was no goodwill impairment as of
December 31, 2004.


CAPITAL EXPENDITURES AND NET ACQUISITIONS

Total capital expenditures, excluding acquisitions and dispositions, totaled
$193.8 million in 2004 compared to $155.8 million in 2003. This amount was
incurred on drilling and completions, geological, geophysical and facilities
expenditures, as ARC continues to develop its asset base. The significant
increase in 2004 capital expenditures relative to 2003 is due to a larger
capital development program in 2004 to capture value from increased development
opportunities as a result of the Star acquisition.

In addition to the capital expenditures, the Trust completed net property
dispositions of $58.2 million, net of post closing adjustments, in 2004. The
Trust also completed two corporate acquisitions, United Prestville in June 2004,
for total consideration of $30.6 million and Harrington & Bibler in December
2004, for total consideration of $41.4 million. Both corporate acquisitions were
undertaken by the Trust to increase the Trust's ownership interest in existing
key properties.

The capital expenditures resulted in an increase in oil and gas reserves, before
dispositions, as detailed in the February 16, 2005, Year End Reserves press
release.

A breakdown of capital expenditures and net acquisitions is shown below:

<TABLE>
<CAPTION>
CAPITAL EXPENDITURES
($ THOUSANDS)                                                                 2004               2003            % CHANGE
--------------------------------------------------------------------------------------------------------------------------
<S>                                                                        <C>               <C>                    <C>
Geological and geophysical                                                   5,388              5,671                  (5)
Drilling and completions                                                   144,487            110,277                  31
Plant and facilities                                                        41,089             36,457                  13
Other capital                                                                2,820              3,359                 (16)
--------------------------------------------------------------------------------------------------------------------------
Total capital expenditures                                                 193,784            155,764                  24
Producing property acquisitions (1)                                           (529)            14,783                (104)
Producing property dispositions (1)                                        (57,691)          (176,392)                 67
Corporate acquisitions (2)                                                  72,009            721,590                 (90)
--------------------------------------------------------------------------------------------------------------------------
Total capital expenditures and net acquisitions                            207,573            715,745                 (71)
Total capital expenditures financed with cash flow                         110,846            106,625                   4
Total capital expenditures financed with debt & equity                      96,727            609,120                 (84)
--------------------------------------------------------------------------------------------------------------------------
</TABLE>

(1) Value is net of post-closing adjustments.

(2) Represents total consideration for the transactions, including fees but is
    prior to the related future income tax liability and working capital assumed
    on acquisition.

ARC expects to undertake significant development projects in 2005 to fully
execute the capital program of approximately $240 million.


ASSET RETIREMENT OBLIGATION AND RECLAMATION FUND

At December 31, 2004, the Trust has recorded an Asset Retirement Obligation
("ARO") of $73 million ($66.7 million at December 31, 2003) for future
abandonment and reclamation of the Trust's properties. The ARO increased by $4.9
million during 2004 as a result of liabilities associated with the acquisitions
of United Prestville and Harrington & Bibler and with additional wells drilled
in 2004, partially offset by the sale of properties in the second quarter of
2004. The ARO further increased by $4.6 million for accretion expense in 2004
($3 million in 2003) and was reduced by $3.2 million ($2.2 million in 2003) for
actual abandonment expenditures incurred in 2004. The Trust did not record a
gain or loss on actual abandonment expenditures incurred in 2004 as the costs
closely approximated the liability value included in the ARO.

ARC contributed $6 million cash to its reclamation fund in 2004 ($5.5 million in
2003) and earned interest of $1.2 million ($0.7 million in 2003) on the fund
balance. The fund balance was reduced by $3.1 million for cash-funded
abandonment expenditures in 2004 ($1.9 million in 2003). This fund, invested in
money market instruments, was established to provide for future abandonment and
reclamation liabilities. Future contributions are currently set at approximately
$6 million per year

<PAGE>
Page 13
--------------------------------------------------------------------------------

over 20 years in order to provide for the total estimated future abandonment and
reclamation costs that are to be incurred over the next 61 years.


CAPITALIZATION, FINANCIAL RESOURCES AND LIQUIDITY

A breakdown of the Trust's capital structure is as follows:

<TABLE>
<CAPTION>
($ THOUSANDS EXCEPT PER UNIT AND PER CENT AMOUNTS)                                             2004                  2003
--------------------------------------------------------------------------------------------------------------------------
<S>                                                                                         <C>                   <C>
Long-term debt                                                                              211,834               223,355
Short-term debt                                                                               8,715                 9,047
Working capital deficit (surplus) excluding short-term debt (1)                              44,293                29,669
--------------------------------------------------------------------------------------------------------------------------
Net debt obligations                                                                        264,842               262,071
Units outstanding and issuable for exchangeable shares (thousands)                          188,804               182,777
Market price per unit at end of period                                                        17.90                 14.74
Market value of trust units and exchangeable shares                                       3,379,592             2,694,133
Total capitalization (2)                                                                  3,644,434             2,956,204
--------------------------------------------------------------------------------------------------------------------------
Net debt as a percentage of total capitalization                                               7.3%                  8.9%
Net debt obligations                                                                        264,842               262,071
Cash flow from operations                                                                   448,033               396,180
Net debt to cash flow                                                                           0.6                   0.7
--------------------------------------------------------------------------------------------------------------------------
</TABLE>

(1) The 2004 working capital deficit excludes the balances for commodity and
    foreign currency contracts.

(2) Total capitalization as presented does not have any standardized meaning
    prescribed by Canadian GAAP and therefore it may not be comparable with the
    calculation of similar measures for other entities. Total capitalization is
    not intended to represent the total funds from equity and debt received by
    the Trust.

On April 27, 2004, the Trust completed the issuance of US$125 million of
long-term secured notes ("US Notes") via a private placement to a small group of
Canadian and United States financial institutions and insurance companies. The
notes were issued in two tranches of US$62.5 million each. The first tranche of
US$62.5 million has a final life of 10 years (average life of 7.5 years) and
pays a semi-annual coupon of 4.62 per cent per annum. The second tranche of
US$62.5 million has a final life of 12 years (average life of 10 years) and pays
a semi-annual coupon of 5.10 per cent per annum. Repayments of the notes will
occur in years 2009 through 2016.

The Trust consolidated its five credit facilities into one syndicated credit
facility with a total borrowing base of $620 million in the second quarter of
2004. The syndication of the credit facilities did not impact the Trust's
borrowing base nor did it impact other key terms of the credit facility such as
security or covenants. Borrowing rates under the syndicated facility decreased
slightly. ARC Resources' and ARC (Sask) Trust's oil and gas properties continue
to secure the debt. The next annual credit review will occur in April 2005 with
the expectation that the current agreement will be renewed under identical or
similar terms and conditions.

The following is a summary of total debt outstanding at the end of the year:

<TABLE>
<CAPTION>
TOTAL DEBT
($ THOUSANDS)                                                                                  2004                  2003
--------------------------------------------------------------------------------------------------------------------------
<S>                                                                                          <C>                   <C>
Revolving credit facilities
      Working capital facility, current                                                         290                    --
      CAD credit facility, 364 day revolving                                                     --               111,298
      USD credit facility, 364 day revolving                                                     --                37,098
Senior secured notes (1)
      US$35 million, 8.05%, 2004 - 2008                                                      33,701                45,234
      US$30 million, 4.94%, 2006 - 2010                                                      36,108                38,772
Long-term notes (1)
      US$62.5 million, 4.62%, 2009 - 2014                                                    75,225                    --
      US$62.5 million, 5.10%, 2011 - 2016                                                    75,225                    --
--------------------------------------------------------------------------------------------------------------------------
Total debt outstanding, long-term and current                                               220,549               232,402
Current portion of debt                                                                       8,715                 9,047
Long-term portion of debt                                                                   211,834               223,355
--------------------------------------------------------------------------------------------------------------------------
</TABLE>

(1) Both the senior secured notes and the long-term notes rank pari passu to the
    revolving credit facilities.

Concurrent with the issuance of the Long-term Notes, the Trust entered into
interest rate swap transactions to effectively convert the fixed interest rate
on US$62.5 million of the US Notes into a floating rate, based on the three
month LIBOR rate plus 38.25 basis points, in order to capitalize on historic low
interest rates in the United States. As a result, the Trust effectively issued
US$125 million notes at an average rate of 3.3 per cent, with this rate
increasing by one half of a percentage point for every one percentage point
increase in short-term U.S. interest rates. The short-term US LIBOR interest
rate was 2.6 per cent at December 31, 2004.

<PAGE>
Page 14
--------------------------------------------------------------------------------

As at December 31, 2004, the Trust had a working capital deficiency excluding
short-term debt, of $48.3 million. Included in the working capital deficit is a
net current liability of $4 million for the fair value loss on commodity and
foreign currency contracts under new hedge accounting guidelines implemented in
2004. Excluding the Trust's net current liability for commodity and foreign
currency contracts and short-term debt, the Trust had a working capital deficit
of $44.3 million at December 31, 2004.

The Trust's working capital deficit, excluding the net liability for commodity
and foreign currency contracts, was significantly higher at December 31, 2004,
compared to December 31, 2003. The Trust fully funded the $41.4 million
Harrington & Bibler acquisition on December 31, 2004, with cash.

December 31, 2004, net debt to total capitalization was 7.3 per cent and net
debt to annual 2004 cash flow was approximately 0.6 times (0.7 times as at
December 31, 2003).

The Trust intends to finance a portion of the $240 million 2005 capital program
with cash flow, proceeds of the distribution reinvestment program and the
remainder will be financed with debt.


UNITHOLDERS' EQUITY

At December 31, 2004, there were 188.8 million trust units issued and issuable
for exchangeable shares, a three per cent increase from the 182.8 million trust
units issued and issuable for exchangeable shares at December 31, 2003. The
increase in the number of trust units outstanding is attributable to two million
trust units issued as consideration for the acquisition of United Prestville at
a price of $15.00 per trust unit, 1.9 million trust units issued pursuant to the
Distribution Reinvestment Incentive Plan ("DRIP") at an average price of $14.72
per trust unit, 1.7 million trust units issued pursuant to the exercise of
employee rights at an average price of $11.70 per trust unit, and 0.4 million
trust units issued upon conversion of exchangeable shares.

The Trust made its final issuance of 27,000 additional rights under the Rights
Plan during the first quarter of 2004. There will be no future issuances of
rights as the rights plan was replaced with a new Whole Unit Plan in the second
quarter of 2004. The existing rights plan will be in place until the remaining
three million rights outstanding as of December 31, 2004, are exercised or
cancelled. The holder has the option to exercise the rights at the original
grant price or a price that is adjusted downward over time by the amount, if
any, of the annual distributions that exceed 10 per cent of the net book value
of the property, plant and equipment. The rights have a five-year term and vest
equally over three years from the date of grant. Rights to purchase three
million trust units at an average adjusted exercise price of $10.92 were
outstanding at December 31, 2004. These rights have an average remaining
contractual life of 3.1 years and expire at various dates to March 22, 2009. Of
the rights outstanding at December 31, 2004, a total of 0.8 million were
exercisable at that time.

The Whole Unit Plan introduced in March 2004 is a cash compensation plan for
employees, officers and directors of the Trust and does not involve any units
being issued from treasury. The Trust has made provisions whereby employees may
elect to have trust units purchased for them on the market with the cash
received upon vesting.

Unitholders electing to reinvest distributions or make optional cash payments to
acquire trust units from treasury under the DRIP may do so at a five per cent
discount to the prevailing market price with no additional fees or commissions.


NON-CONTROLLING INTEREST - EXCHANGEABLE SHARES

The Trust has recorded non-controlling interest attributed to the issued and
outstanding exchangeable shares of ARC Resources Ltd. ("ARL") in accordance with
new accounting requirements pursuant to the Canadian Institute of Chartered
Accountants Emerging Issues Committee's Pronouncement 151 ("EIC-151") (see
"Impact of New Accounting Policies" in this MD&A and Note 3 of the consolidated
financial statements for further discussion). The intent of the new standard is
that exchangeable shares of a subsidiary which are transferable to third parties
represent a non-controlling interest in the subsidiary.

The exchangeable shares of ARL are publicly traded and therefore are
transferable to third parties. In all circumstances, including in the event of
the liquidation or insolvency of ARL, holders of exchangeable shares will
receive trust units in exchange for their exchangeable shares and as a result
the exchangeable shares and trust units are considered to be economically
equivalent. The Trust does not believe that there is a permanent non-controlling
interest as all exchangeable shares will ultimately be exchanged for trust units
by passage of time. Over time, the non-controlling interest will decrease and
eventually will be nil when all exchangeable shares have been exchanged for
trust units on or before August 29, 2012.

The non-controlling interest in 2004 of $36 million ($36.3 million in 2003) on
the consolidated balance sheet represents the book value of exchangeable shares
plus accumulated earnings attributable to the outstanding exchangeable shares.
The reduction in 2004 and 2003 net income, respectively, of $4 million and $5.6
million, represents the net income attributable to the exchangeable shareholders
for 2004 and 2003. As the exchangeable shares are converted to trust units,
Unitholders' capital is increased for the book value of the trust units issued.

As at December 31, 2004, there were 1.8 million exchangeable shares of ARL
outstanding at exchange ratio of 1.67183 whereby three million trust units would
be issuable upon conversion. The exchangeable shares can be converted into trust

<PAGE>
Page 15
--------------------------------------------------------------------------------

units or redeemed by the exchangeable shareholder for trust units at any time.
ARL may redeem all outstanding exchangeable shares on or before August 29, 2012,
and may redeem the exchangeable shares at any time if the number of exchangeable
shares outstanding falls below 100,000 shares. ARL may issue cash or trust units
upon redemption of exchangeable shares and it is the intention to issue trust
units upon redemption.


CASH DISTRIBUTIONS

ARC declared cash distributions of $330 million ($1.80 per unit), representing
74 per cent of 2004 cash flow compared to cash distributions of $279.3 million
($1.80 per unit), representing 71 per cent of cash flow in 2003. The remaining
26 per cent of 2004 cash flow ($118 million) was used to fund 57 per cent of
ARC's 2004 capital expenditures ($110.8 million), and make contributions,
including interest, to the reclamation fund ($7.2 million). The actual amount of
cash flow withheld to fund the Trust's capital expenditure program is dependent
on the commodity price environment and is at the discretion of the Board of
Directors.

Cash flow and cash distributions in total and per unit for 2004 and 2003 were as
follows:

<TABLE>
<CAPTION>
2004 Cash Flow and Distributions
                                                 2004       2003        % CHANGE               2004      2003    % CHANGE
--------------------------------------------------------------------------------------------------------------------------
                                                                    ($ millions)                             ($ per unit)
<S>                                             <C>        <C>                <C>              <C>       <C>           <C>
Cash flow from operations                       448.0      396.2              13               2.45      2.61          (6)
Reclamation fund contributions (1)               (7.2)      (6.2)             16              (0.04)    (0.04)         --
Capital expenditures
     funded with cash flow                     (110.8)    (106.6)              4              (0.61)    (0.70)        (13)
Interest on convertible debentures                 --       (4.1)             --                 --     (0.03)         --
Other (2)                                          --         --              --                 --     (0.04)         --
--------------------------------------------------------------------------------------------------------------------------
Cash distributions                              330.0      279.3              18               1.80      1.80          --
</TABLE>

(1) Includes interest income earned on the reclamation fund balance that is
    retained in the reclamation fund.

(2) Other represents the difference due to cash distributions paid being based
    on actual units at each distribution date whereas per unit cash flow,
    reclamation fund contributions and capital expenditures funded with cash
    flow are based on weighted average trust units in the year.

Monthly cash distributions for the first quarter of 2005 have been set at $0.15
per trust unit subject to monthly review based on commodity price fluctuations.
Revisions, if any, to the monthly distribution are normally announced on a
quarterly basis in the context of prevailing and anticipated commodity prices at
that time.


HISTORICAL CASH DISTRIBUTIONS BY CALENDAR YEAR

The following table presents cash distributions paid in each calendar period.
Cash distributions for 2004 include distributions paid up to and including
December 15, 2004:

<TABLE>
<CAPTION>
CALENDAR YEAR                                    DISTRIBUTIONS(1)            TAXABLE PORTION          RETURN OF CAPITAL
---------------------------------------------------------------------------------------------------------------------
<C>                                                     <C>                      <C>                         <C>
2005 YTD (2)                                              0.30                     0.29(2)                     0.01(2)
2004                                                      1.80                     1.69(3)                     0.11(3)
2003                                                      1.78                     1.51                        0.27
2002                                                      1.58                     1.07                        0.51
2001                                                      2.41                     1.64                        0.77
2000                                                      1.86                     0.84                        1.02
1999                                                      1.25                     0.26                        0.99
1998                                                      1.20                     0.12                        1.08
1997                                                      1.40                     0.31                        1.09
1996                                                      0.81                       --                        0.81
---------------------------------------------------------------------------------------------------------------------
Cumulative                                             $ 14.39                   $ 7.73                      $ 6.66
---------------------------------------------------------------------------------------------------------------------
</TABLE>

(1) Based on cash distributions paid in the calendar year.

(2) Based on cash distributions paid in 2005 up to and including February 15,
    2005, and estimated taxable portion of 2005 distributions of 95 per cent.

(3) Based on taxable portion of 2004 distributions of 94 per cent.

<PAGE>
Page 16
--------------------------------------------------------------------------------

2004 MONTHLY CASH DISTRIBUTIONS

Actual cash distributions paid for 2004 along with relevant payment dates are as
follows:

<TABLE>
<CAPTION>
                                                    DISTRIBUTION                  TOTAL        TAXABLE          RETURN OF
EX-DISTRIBUTION DATE       RECORD DATE              PAYMENT DATE            DISTRIBUTION        PORTION           CAPITAL
--------------------------------------------------------------------------------------------------------------------------
<S>                        <C>                      <C>                             <C>           <C>               <C>
December 29, 2003          December 31, 2003        January 15, 2004                0.15          0.141             0.009
January 28, 2004           January 31, 2004         February 16, 2004               0.15          0.141             0.009
February 25, 2004          February 29, 2004        March 15, 2004                  0.15          0.141             0.009
March 29, 2004             March 31, 2004           April 15, 2004                  0.15          0.141             0.009
April 28, 2004             April 30, 2004           May 17, 2004                    0.15          0.141             0.009
May 27, 2004               May 31, 2004             June 15, 2004                   0.15          0.141             0.009
June 28, 2004              June 30, 2004            July 15, 2004                   0.15          0.141             0.009
July 28, 2004              July 31, 2004            August 16, 2004                 0.15          0.141             0.009
August 27, 2004            August 31, 2004          September 15, 2004              0.15          0.141             0.009
September 28, 2004         September 30, 2004       October 15, 2004                0.15          0.141             0.009
October 27, 2004           October 31, 2004         November 15, 2004               0.15          0.141             0.009
November 26, 2004          November 30, 2004        December 16, 2004               0.15          0.141             0.009
--------------------------------------------------------------------------------------------------------------------------
Total 2004                                                                          1.80          1.69               0.11
</TABLE>

TAXATION OF CASH DISTRIBUTIONS

Cash distributions comprise a return of capital portion (tax deferred) and a
return on capital portion (taxable). The return of capital component reduces the
cost basis of the trust units held. The tables above and following discussion
relate to taxation of Canadian unitholders. For a more detailed breakdown and
for tax information for foreign or U.S. investors, please visit our website at
www.arcenergytrust.com.

For 2004, cash distributions paid in the calendar year will be 94 per cent
return on capital (taxable) and six per cent return of capital (tax deferred).
The increase in the taxable portion of distributions to 94 per cent is the
result of increasing commodity prices and in turn, increasing cash flow of the
Trust. Actual taxable amounts may differ from the estimated amount as they are
dependent on commodity prices experienced throughout the year. Changes in the
estimated taxable and deferred portion of the distributions will be announced
quarterly.

The exchangeable shares of ARC Resources Ltd. ("ARL"), a corporate subsidiary of
the Trust, may provide a more tax-effective basis for investment in the Trust.
The ARL exchangeable shares are traded on the TSX under the symbol "ARX" and are
convertible into trust units, at the option of the shareholder, based on the
then current exchange ratio. Exchangeable shareholders are not eligible to
receive monthly cash distributions; however, the exchange ratio increases on a
monthly basis by an amount equal to the current month's trust unit distribution
multiplied by the then current exchange ratio and divided by the 10 day weighted
average trading price of the trust units at the end of each month. The gain
realized as a result of the monthly increase in the exchange ratio is taxed, in
most circumstances, as a capital gain rather than income and is therefore
subject to a lower effective tax rate. Tax on the exchangeable shares is
deferred until the exchangeable share is sold or converted into a trust unit.


CONTRACTUAL OBLIGATIONS AND COMMITMENTS

The Trust has contractual obligations in the normal course of operations,
including purchase of assets and services, operating agreements, transportation
commitments, sales commitments, royalty obligations and lease rental
obligations. These obligations are of a recurring and consistent nature and
impact cash flow in an ongoing manner. The Trust also has contractual
obligations and commitments that are of a less routine nature and that are
disclosed in Note 18 of the consolidated financial statements.

The Trust enters into commitments for capital expenditures in advance of the
expenditures being made. At a given point in time, it is estimated that the
Trust has committed to approximately $40 to $60 million of capital expenditures
by means of giving the necessary authorizations to incur the capital in a future
period. This commitment has not been disclosed in the above commitment table as
it is of a routine nature and is part of normal course of operations for active
oil and gas companies and trusts.

The Trust has certain sales contracts with aggregators whereby the price
received by the Trust is dependent upon the contracts entered into by the
aggregator. The Trust has an obligation for future fixed transportation charges,
pursuant to one aggregator contract, for which the transportation is not
physically being utilized due to a shortage of demand. The Trust has estimated
that its total liability for the future transportation charges approximates $10
million over the period 2005 through 2012. This transportation liability will be
realized as a reduction of the Trust's net gas price over the corresponding
period as the charges are incurred. For all other aggregator contracts, prices
received by the Trust closely track to market prices.

<PAGE>
Page 17
--------------------------------------------------------------------------------

The Trust is involved in litigation and claims arising in the normal course of
operations. Management is of the opinion that pending litigation will not have a
material adverse impact on the Trust's financial position or results of
operations.


OFF BALANCE SHEET ARRANGEMENTS

The Trust has certain lease agreements that are entered into in the normal
course of operations. All leases are treated as operating leases whereby the
lease payments are included in operating expenses or G&A expenses depending on
the nature of the lease. No asset or liability value has been assigned to these
leases in the balance sheet as of December 31, 2004. The total obligation for
future lease payments under all operating leases is disclosed in the
"Contractual Obligations and Commitments" section above.

The Trust entered into agreements to pay premiums pursuant to certain crude oil
derivative put contracts. Premiums of approximately $29.4 million will be paid
in 2005 for the put contracts in place at year end. As the premiums are part of
the underlying derivative contract, they have been recorded at fair market value
at December 31, 2004, on the balance sheet. The total obligation for future
premium payments is disclosed in the "Contractual Obligations and Commitments"
section above and Note 18 of the consolidated financial statements.


IMPACT OF NEW ACCOUNTING POLICIES

In 2004 the Trust implemented the following new accounting policies and
instruments pursuant to requirements of the Canadian Institute of Chartered
Accountants ("CICA"). The implementation of these new policies impacted the
financial results for 2004 and comparative periods of 2003 as follows:

Non-Controlling Interest - On January 19, 2005, the CICA issued EIC-151
"Exchangeable Securities Issued by Subsidiaries of Income Trusts" which states
that exchangeable securities issued by a subsidiary of an income trust should be
reflected as either non-controlling interest or debt on the consolidated balance
sheet unless they meet certain criteria. The exchangeable shares issued by ARL,
a corporate subsidiary of the Trust, are publicly traded and therefore must be
presented as non-controlling interest, outside of Unitholders' equity.
Previously, the exchangeable shares were reflected as a component of
Unitholders' equity. Accordingly, the Trust has reflected a non-controlling
interest of $36 million and $36.3 million, respectively, on the Trust's
consolidated balance sheet as at December 31, 2004, and 2003. Consolidated net
income has been reduced for net income attributable to the non-controlling
interest of $4 million and $5.6 million, respectively, in 2004 and 2003. In
accordance with the transitional provisions of EIC-151, retroactive application
has been applied with restatement of prior periods. As a result of retroactive
restatement, opening accumulated earnings for 2003 decreased by $5.5 million for
the cumulative net income attributable to the non-controlling interest,
Unitholders' equity was reduced by $31.7 million and non-controlling interest on
the balance sheet increased by $37.2 million.

Hedge Accounting - In December 2001, the CICA issued Accounting Guideline 13
"Hedging Relationships" and EIC-128 "Accounting for Trading, Speculative, or
Non-Hedging Derivative Financial Instruments" that deal with the identification,
designation, documentation and measurement of effectiveness of hedging
relationships for the purposes of applying hedge accounting. Accounting
Guideline 13 ("AcG-13") is intended to harmonize Canadian GAAP with SFAS No.133
"Accounting for Derivatives Instruments and Hedging Activities". AcG-13 is
effective for fiscal years beginning on or after July 1, 2003, and upon
implementation of AcG-13, accounting in accordance with EIC-128 is required.

The Trust implemented AcG-13 in the first quarter of 2004 along with accounting
in accordance with EIC-128. As a result, certain of the Trust's derivative
contracts were designated as effective hedges for accounting purposes at January
1, 2004. Commodity and foreign currency contracts that were designated as
effective hedges continue to be accounted for in the same manner as in previous
periods whereby realized gains and losses on effective hedges are netted against
the item to which they relate in the statement of income. Commodity and foreign
currency contracts that were not designated as effective hedges for accounting
purposes are subject to fair value accounting in accordance with EIC-128, which
requires that changes in the fair value of these derivative contracts be
reported as income or expense in each reporting period. The income or expense
relating to the change in fair value of the derivative contracts is a non-cash
(unrealized) expense that has no impact on cash flow but may result in
significant fluctuations in net income due to volatility in the underlying
market commodity prices and foreign exchange rates.

Prior to implementation of AcG-13 and EIC-128, the Trust accounted for all
derivative contracts as effective hedges whereby realized gains and losses on
such contracts were included in the statement of income within the corresponding
item to which the hedge pertained. Following implementation, realized and
unrealized gains and losses on derivative contracts that do not qualify as
effective hedges are reported as a separate expense in the statement of income.
In accordance with the transitional provisions of AcG-13 and EIC-128, this new
guideline has been applied prospectively whereby prior periods have not been
restated.

As an example of a commodity derivative contract, the Trust enters into oil and
natural gas put options as part of its commodity risk management portfolio. The
Trust considers such a transaction to be an effective economic hedge as it
reduces exposure to decreases in commodity prices that would adversely impact
cash flow and allows the Trust to

<PAGE>
Page 18
--------------------------------------------------------------------------------

participate in 100 per cent of the upside over and above the contract price. Per
new hedge accounting requirements, this transaction does not qualify as an
effective accounting hedge and therefore is subject to fair value accounting.

As a result of implementation of this new standard, 2004 net income decreased by
$2.6 million ($4 million before a future income tax recovery of $1.4 million).
The entire $4 million decrease in 2004 pre-tax net income was the result of
non-cash losses due to changes in the fair value of the contracts. On initial
implementation of this standard on January 1, 2004, the Trust recorded an
opening deferred charge of $14.6 million equal to the fair value of derivative
contracts at that time. The deferred charge was amortized to earnings over the
life of the respective contracts in place at January 1, 2004, and was fully
amortized as of December 31, 2004. The Trust recorded a derivative asset of
$22.3 million and a derivative liability of $26.3 million for the fair value of
the derivative contracts as at December 31, 2004 (nil impact in 2003). There was
no impact on cash flow as a result of implementing this new standard.

Transportation Costs - Effective in 2004, the Trust revised its presentation of
transportation costs in accordance with CICA Handbook Section 1100 "Generally
Accepted Accounting Principles". As a result, revenue has been presented prior
to transportation costs and a separate expense for transportation costs has been
presented in the statement of income. The Trust has reclassified previously
reported amounts to be consistent with the presentation under this new policy.
Transportation costs of $14.8 million and $12 million, respectively, were
recorded in 2004 and 2003 as a result of this new policy. There was no impact on
net income or cash flow in 2004 nor did it impact restated net income or cash
flow in 2003.

Recognition of Temporary Equity for US GAAP Purposes - For Canadian income tax
purposes the Trust qualifies as a mutual fund trust by the fact that the Trust's
indenture contains redemption provisions. For US GAAP purposes this redemption
feature has resulted in the Trust reflecting all of its equity in 2004 and
restating its 2003 accounts to record "temporary equity" as prescribed under
Emerging Issues Task Force D-98 due to the fact unitholders have a right to have
the Trust redeem their units rather than selling the units on the Toronto Stock
Exchange. The reclassification of Unitholders' equity to temporary equity is
recorded at fair market value of the trust units at year end (see Note 19 of the
consolidated financial statements).The Trust's redemption features allow for
cash redemptions to a maximum of $100,000 per month at a price calculated at a
discount to the market trading price with redemption requests in excess of the
$100,000 monthly maximum being satisfied by issuing a 15 year note from
ARCResources Ltd. for a maximum amount of $500 million that would rank
subordinate to all other creditors and not be listed on any exchange resulting
in limited liquidity. Further, the Trust has a termination date of December 31,
2095, if not extended by the unitholders prior to that time, at which time the
Trust would commence wind-up activities by redeeming all outstanding units and
distributing the remaining assets, if any, to unitholders. As such, it is in
management's opinion that the required classification of the Trust's units as
"temporary equity" does not meaningfully represent the true nature of the
Trust's financial picture. For Canadian GAAP purposes the proceeds of units
issued has been classified on the balance sheet as "Unitholder's Capital".


FINANCIAL REPORTING UPDATE

In addition to the above policies implemented in 2004, the following new and
amended standards and proposed standards have been reviewed by the Trust:

Variable Interest Entities - In June 2003 the CICA issued Accounting Guideline
15 "Consolidation of Variable Interest Entities" that deals with the
consolidation of entities which are subject to control on a basis other than
ownership of voting interests. This new guideline is effective for fiscal years
beginning on or after November 1, 2004. The Trust has assessed that this
guideline has no current or future impact based on the current structure. The
Trust will consider the applicability of this guideline in the future and assess
the appropriate financial statement implications at that time.

Redeemable or Retractable Shares - On November 5, 2004, the CICA issued EIC-149
"Accounting for Retractable or Mandatorily Redeemable Shares" that lists
specific criteria required to be met in order for entities to reflect trust
units and exchangeable shares as either a liability or equity in their financial
statements. The trust units and exchangeable shares meet the required criteria
to be reflected as Unitholders' equity and no additional presentation or
disclosure is required.

Financial Instruments - Recognition and Measurement - On January 27, 2005, the
Accounting Standard's Board (AcSB) issued CICA Handbook section 3855 "Financial
Instruments - Recognition and Measurement", CICA Handbook section 1530
"Comprehensive Income" and CICA Handbook section 3865 "Hedges" that deal with
the recognition and measurement of financial instruments and comprehensive
income. The new standards are intended to harmonize Canadian standards with
United States and International accounting standards and are effective for
annual and interim periods in fiscal years beginning on or after October 1,
2006. These new standards will impact the Trust in future periods and the
resulting impact will be assessed at that time.


CRITICAL ACCOUNTING ESTIMATES

The Trust has continuously evolved and documented its management and internal
reporting systems to provide assurance that accurate, timely internal and
external information is gathered and disseminated.

<PAGE>
Page 19
--------------------------------------------------------------------------------

The Trust's financial and operating results incorporate certain estimates
including:

a) estimated revenues, royalties and operating costs on production as at a
   specific reporting date but for which actual revenues and costs have not yet
   been received;
b) estimated capital expenditures on projects that are in progress;
c) estimated depletion, depreciation and accretion that are based on estimates
   of oil and gas reserves which the Trust expects to recover in the future;
d) estimated fair values of derivative contracts that are subject to fluctuation
   depending upon the underlying commodity prices and foreign exchange rates;
e) estimated value of asset retirement obligations that are dependent upon
   estimates of future costs and timing of expenditures; and
f) estimated future recoverable value of property, plant and equipment and
   goodwill.

The Trust has hired individuals and consultants who have the skill set to make
such estimates and ensures individuals or departments with the most knowledge of
the activity are responsible for the estimates. Further, past estimates are
reviewed and compared to actual results, and actual results are compared to
budgets in order to make more informed decisions on future estimates.

The ARC leadership team's mandate includes ongoing development of procedures,
standards and systems to allow ARC staff to make the best decisions possible and
ensuring those decisions are in compliance with the Trust's environmental,
health and safety policies.


SARBANES-OXLEY UPDATE

On July 31, 2002, the United States Congress enacted the Sarbanes-Oxley Act
("SOX"). SOX applies to all companies registered with the Securities and
Exchange Commission ("SEC"). Although ARC is not listed on a U.S. stock
exchange, the Trust is registered with the SEC as a result of having acquired
Startech Energy Inc. in 2001 and therefore is required to comply with the SOX
legislation. There are various components to the SOX legislation, however the
most comprehensive is Section 404 "Internal Controls Over Financial Reporting".
Section 404 requires that management undertake the following:

o   identify and document internal controls that impact financial reporting;

o   assess the effectiveness of those internal controls;

o   remediate any deficiencies in internal controls and/or implement any
    required controls that are not already in place;

o   test the internal controls to ensure that they are operating effectively;
    and

o   issue a report, to be signed by the CEO and CFO, on management's assessment
    of the effectiveness of internal controls and communicate any material
    weaknesses.

ARC is currently required to comply with section 404 of the SOX legislation on
December 31, 2005. In conjunction with the 2005 year end audit, ARC's external
auditors will audit the Trust's internal controls and will issue two opinions,
one on the auditor's assessment of the effectiveness of internal controls and
one on the auditor's opinion on management's assessment of the same internal
controls.

The Trust currently has a comprehensive plan and a dedicated team of individuals
in place to execute the plan of meeting the SOX Section 404 compliance date.

In addition to SOX, ARC is required to comply with Multilateral Instrument
52-109 "Certification of Disclosure in Issuers' Annual and Interim Filings",
otherwise referred to as Canadian SOX ("C-Sox"). ARC is currently complying with
this legislation by filing Bare Interim and Annual Certificates. It is expected
that ARC will be required to file a Full Annual certificate in conjunction with
the December 31, 2006, year end. The Canadian requirements closely parallel the
SEC's certification rules; however, currently there is no requirement to have an
external auditor's opinion on the Trust's internal controls or management's
assessment thereof.


OBJECTIVES AND 2005 OUTLOOK

It is the Trust's objective to provide the highest possible long-term returns to
unitholders by focusing on the key strategic objectives of the business plan.
The Trust has provided unitholders with the following one, three and five year
returns:

<TABLE>
<CAPTION>
TOTAL RETURNS
($ PER TRUST UNIT EXCEPT FOR PER CENT)                 ONE YEAR     THREE YEAR    FIVE YEAR
--------------------------------------------------------------------------------------------
<S>                                                   <C>            <C>            <C>
Distributions per trust unit                               1.80           5.16         9.48
Capital appreciation per trust unit                        3.16           5.80         9.15
--------------------------------------------------------------------------------------------
Total return per trust unit                           $    4.96      $   10.96      $ 18.63
Annualized total return per trust unit                    35.8%          29.3%        39.6%
--------------------------------------------------------------------------------------------
</TABLE>

<PAGE>
Page 20
--------------------------------------------------------------------------------

To the end of 2004, the Trust has provided cumulative cash distributions of
$14.24 per trust unit and capital appreciation of $7.90 per trust unit for a
total return of $22.14 per trust unit (24.3 per cent annualized total return)
for unitholders who invested in the Trust at inception.

The key future objectives of the Trust's business plan, as identified below, are
reviewed by the Board annually. In 2004 the Trust was successful in meeting all
of its objectives, which are individually addressed below.

o  Annual reserve replacement - The Trust incurred a slight decrease in 2004
   reserves as a result of the divestment of non-core assets in 2004. However,
   the Trust's change in oil and gas reserves, excluding the disposition,
   validated the successful nature of the Trust's internal development program
   in 2004.

o  Ensuring acquisitions are strategic and enhance unitholder returns - The
   Trust completed two small corporate acquisitions in 2004, which resulted in
   increased ownership in certain key properties and provide for future
   development potential for the Trust.

o  Controlling costs - Costs of developing properties, operating costs and G&A
   expenses - In 2004 the Trust continued to closely monitor operating expenses
   and divested of higher cost properties. This resulted in relatively unchanged
   operating costs despite increasing cost trends throughout the industry in
   2004. The Trust realized lower interest expense due to lower debt levels in
   2004. Cash G&A expenses increased slightly in 2004 as a result of increased
   industry competition for employees resulting in increased compensation
   levels. The Trust's three year average cost of developing properties is
   expected to be one of the lowest in the trust sector as disclosed in a press
   release dated February 16, 2005, on year end 2004 oil and gas reserves.

o  Actively hedging a portion of the Trust's production to protect minimum
   distributions - The Trust updated its hedging strategy in late 2004 with the
   objective of maintaining cash flow and distributions, while allowing the
   Trust to participate in a greater portion of the upside in a rising commodity
   price environment.

o  Conservative utilization of debt - The Trust's debt levels were under 10 per
   cent of total capitalization and debt to 2004 cash flow was 0.6 times for the
   year ended 2004.

o  Continuously developing the expertise of our staff and seeking to hire and
   retain the best in the industry - The Trust continued to assess compensation
   levels in the industry to ensure that the Trust's compensation is competitive
   so as to ensure that we can attract and retain the best employees. In
   addition, the Trust implemented a new Whole Unit Plan that is a long-term
   incentive based plan for all employees of the Trust.

o  Demonstrating leadership - The Trust led an industry initiative to lobby the
   Province of Alberta to provide limited liability protection for investors in
   income and royalty trusts. On July 1, 2004, limited liability protection was
   put in place for Alberta registered trusts. ARC continues to be viewed as an
   industry leader on this and other industry initiatives.

o  Promoting the use of proven and effective technologies - The Trust continues
   to research new technologies in an effort to conduct its operations in the
   most efficient and cost effective manner.

o  Being an industry leader in the environment, health and safety area - The
   Trust was recognized as a Gold Champion Level Reporter again in 2004 under
   the Canada Climate Change VCR initiative for reducing greenhouse gas
   emissions. In addition, the Trust continues to focus on safety as a number
   one consideration in conducting its operations.

o  Continuing to actively support local initiatives in the communities in which
   we operate and live - The Trust is actively involved in charitable and
   philanthropic causes both in Calgary and in the rural communities in which it
   operates. ARC continued to be a strong supporter of the United Way, Alberta
   Cancer Foundation, Alberta Children's Hospital and many community
   organizations in rural centres.

During 2005 ARC will continue to be active with a robust drilling and
development program on its diverse asset base. The $240 million capital
expenditure budget for 2005 is the largest in the Trust's history, excluding
acquisitions. The Trust will prudently deploy capital with a balanced drilling
program of low and moderate risk wells. The 2004 drilling program resulted in a
99 per cent success rate. The Trust continues to focus on major properties with
significant upside, with the objective to replace production declines through
internal development opportunities.

The low debt levels and strong working capital position provide the Trust with
the financial flexibility to fund the 2005 capital expenditure program and be
poised to take advantage of accretive acquisition opportunities.

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Following is a summary of the Trust's 2005 Guidance issued by way of press
release on January 3, 2005:

<TABLE>
<CAPTION>
                                                             2005 GUIDANCE         ACTUAL 2004        % CHANGE
---------------------------------------------------------------------------------------------------------------
<S>                                                                 <C>                 <C>                <C>
Production (boe/d)                                                  54,800              56,870             ( 4)
Expenses ($/boe):
     Operating costs                                                  7.00                6.71               4
     Transportation                                                   0.70                0.71              (1)
     G&A expenses - cash                                              1.25                1.03              21
     G&A expenses - stock compensation plans                          0.30                0.39             (23)
     Interest                                                         0.75                0.64              17
     Taxes                                                            0.15                0.14               7
Capital expenditures ($ millions)                                      240                 194              24
Weighted average trust units (millions)                              191.0               183.1               3
---------------------------------------------------------------------------------------------------------------
</TABLE>

2005 CASH FLOW SENSITIVITY

Below is a table that illustrates sensitivities to pre-hedged cash flow with
operational changes and changes to the business environment:

<TABLE>
<CAPTION>
                                                   IMPACT ON ANNUAL CASH FLOW             IMPACT ON ANNUAL DISTRIBUTIONS (2)
                                           ASSUMPTION        CHANGE         $/UNIT                 %           $/UNIT
----------------------------------------------------------------------------------------------------------------------------
<S>                                         <C>             <C>            <C>                   <C>          <C>
Business environment
Oil price (US$WTI/barrel) (1)               $  40.00        $ 1.00         $   0.05              2.1%         $   0.04
Natural gas price (CDN$AECO/mcf) (1)        $   6.00        $ 0.10         $   0.03              1.1%         $   0.02
USD/CAD exchange rate                       $   0.82        $ 0.01         $   0.04              1.7%         $   0.03
Interest rate on debt                           4.9%          1.0%         $   0.01              0.6%         $   0.01
----------------------------------------------------------------------------------------------------------------------------
Operational
Liquids production volume (bbls/d)            26,500          1.0%         $   0.01              0.6%         $   0.01
Gas production volumes (mmcf/d)                170.0          1.0%         $   0.02              0.6%         $   0.01
Operating expenses per boe                  $   7.00          1.0%         $   0.01              0.3%         $   0.01
Cash G&A expenses per boe                   $   1.25         10.0%         $   0.02              0.6%         $   0.01
----------------------------------------------------------------------------------------------------------------------------
</TABLE>
(1) Analysis does not include the effect of hedging.
(2) Analysis assumes a 20 per cent holdback on distributions.


ASSESSMENT OF BUSINESS RISKS

The ARC management team is focused on long-term strategic planning and has
identified the key risks, uncertainties and opportunities associated with the
Trust's business that can impact the financial results as follows:


RESERVE ESTIMATES
The reserve and recovery information contained in ARC's independent reserve
evaluation is only an estimate. The actual production and ultimate reserves from
the properties may be greater or less than the estimates prepared by the
independent reserve evaluator. A significant portion of the principal properties
acquired in the Star acquisition have relatively short production histories that
may make estimates on those properties more subject to revisions. The reserve
report was prepared using certain commodity price assumptions that are described
in the notes to the reserve tables. If lower prices for crude oil, natural gas
liquids and natural gas are realized by the Trust and substituted for the price
assumptions utilized in those reserve reports, the present value of estimated
future net cash flows for the Trust's reserves would be reduced and the
reduction could be significant, particularly based on the constant price case
assumptions.


VOLATILITY OF OIL AND NATURAL GAS PRICES

The Trust's operational results and financial condition, and therefore the
amount of distributions paid to the unitholders will be dependent on the prices
received for oil and natural gas production. Oil and gas prices have fluctuated
widely during recent years and are determined by economic and in the case of oil
prices, political factors. Supply and demand factors, including weather and
general economic conditions as well as conditions in other oil and natural gas
regions impact prices. Any movement in oil and natural gas prices could have an
effect on the Trust's financial condition and therefore on the distributions to
the holders of trust units. ARC may manage the risk associated with changes in
commodity prices by entering into oil or natural gas price hedges. If ARC hedges
its commodity price exposure, the Trust will forego the benefits it would
otherwise experience if commodity prices were to increase. In addition,
commodity hedging activities could expose ARC to losses. To the extent that ARC
engages in risk management activities related to commodity prices, it will be
subject to credit risks associated with counterparties with which it contracts.


VARIATIONS IN INTEREST RATES AND FOREIGN EXCHANGE RATES

Variations in interest rates could result in a significant increase in the
amount the Trust pays to service debt, resulting in a decrease in distributions
to unitholders. World oil prices are quoted in U.S. dollars and the price
received by Canadian producers is therefore affected by the Canadian/U.S. dollar
exchange rate that may fluctuate over time. A material increase in the value of
the Canadian dollar may negatively impact the Trust's net production revenue. In
addition, the exchange

<PAGE>
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rate for the Canadian dollar versus the U.S. dollar has increased significantly
over the last 12 months, resulting in the receipt by the Trust of fewer Canadian
dollars for its production, which may affect future distributions. ARC has
initiated certain hedges to attempt to mitigate these risks. To the extent that
ARC engages in risk management activities related to foreign exchange rates, it
will be subject to credit risk associated with counterparties with which it
contracts. The increase in the exchange rate for the Canadian dollar and future
Canadian/U.S. exchange rates will impact future distributions and the future
value of the Trust's reserves as determined by independent evaluators.

The Trust carries on all of its Saskatchewan operations through a trust
structure. As a result of this structure, the Trust is not subject to
Saskatchewan capital tax because the Saskatchewan capital tax legislation only
applies to corporations. Due to the increase in the number of oil and gas
producers that are now operating in Saskatchewan through a trust structure, the
Saskatchewan government is currently considering the inclusion of trusts into
its capital tax legislation. If the Saskatchewan capital tax legislation is
amended to include trusts, the Trust will effectively be subject to a 3.6 per
cent resource surcharge on all of its oil and gas working interest revenue
earned in Saskatchewan.


CHANGES IN LEGISLATION

Income tax laws, or other laws or government incentive programs relating to the
oil and gas industry, such as the treatment of mutual fund trusts, assessment of
provincial capital taxes and resource taxation deductions and allowances, may in
the future be changed or interpreted in a manner that adversely affects the
Trust and its unitholders. Tax authorities having jurisdiction over the Trust or
the unitholders may disagree with how the Trust calculates its income for tax
purposes or could change administrative practices to the detriment of the Trust
or the detriment of its unitholders. ARC intends that the Trust will continue to
qualify as a mutual fund trust for purposes of the Tax Act. The Trust may not
however, always be able to satisfy any future requirements for the maintenance
of mutual fund trust status. Should the status of the Trust as a mutual fund
trust be lost or successfully challenged by a relevant tax authority, certain
adverse consequences may arise for the Trust and its unitholders.


OPERATIONAL MATTERS

The operation of oil and gas wells involves a number of operating and natural
hazards that may result in blowouts, environmental damage and other unexpected
or dangerous conditions, resulting in damage to operating subsidiaries of the
Trust and possible liability to third parties. ARC will maintain liability
insurance, where available, in amounts consistent with industry standards.
Business interruption insurance may also be purchased for selected facilities,
to the extent that such insurance is available. ARC may become liable for
damages arising from such events against which it cannot insure, or against
which it may elect not to insure, because of high premium costs or other
reasons. Costs incurred to repair such damage or pay such liabilities will
reduce distributable cash.

Continuing production from a property, and to some extent the marketing of
production therefrom, are largely dependent upon the ability of the operator of
the property. Operating costs on most properties have increased steadily over
recent years. To the extent the operator fails to perform these functions
properly, revenue may be reduced. Payments from production generally flow
through the operator and there is a risk of delay and additional expense in
receiving such revenues if the operator becomes insolvent. Although satisfactory
title reviews are generally conducted in accordance with industry standards,
such reviews do not guarantee or certify that a defect in the chain of title may
not arise to defeat the claim of the Trust to certain properties. A reduction of
the distributions could result in such circumstances.


EXPANSION OF OPERATIONS

The operations and expertise of management of the Trust are currently focused on
conventional oil and gas production and development in the western Canadian
sedimentary basin. In the future, the Trust may acquire oil and gas properties
outside this geographic area. In addition, the Trust Indenture does not limit
the activities of the Trust to oil and gas production and development, and the
Trust could acquire other energy related assets, such as oil and natural gas
processing plants or pipelines, or an interest in an oilsands project. Expansion
of our activities into new areas may present new additional risks or
alternatively, significantly increase the exposure to one or more of the present
risk factors, which may result in future operational and financial conditions of
the Trust being adversely affected.


ACQUISITIONS

The price paid for reserve acquisitions is based on engineering and economic
estimates of the reserves made by independent engineers modified to reflect the
technical views of management. These assessments include a number of material
assumptions regarding such factors as recoverability and marketability of oil,
natural gas, natural gas liquids and sulphur, future prices of oil, natural gas,
natural gas liquids and sulphur and operating costs, future capital expenditures
and royalties and other government levies that will be imposed over the
producing life of the reserves. Many of these factors are subject to change and
are beyond the control of the operators of the working interests, management and
the Trust. In particular, changes in the prices of and markets for petroleum,
natural gas, natural gas liquids and sulphur from those anticipated at the time
of marking such assessments will affect the amount of future distributions and
as such, the value of the trust units. In addition, all such estimates involve a
measure of geological and engineering uncertainty that could result in lower
production and reserves than attributed to the working interests. Actual
reserves could vary materially from these estimates. Consequently, the reserves
acquired may be less than expected, which could adversely impact cash flows and
distributions to unitholders.

<PAGE>
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ENVIRONMENTAL CONCERNS

The oil and natural gas industry is subject to environmental regulation pursuant
to local, provincial and federal legislation. A breach of such legislation may
result in the imposition of fines or issuance of clean up orders in respect of
ARC or its working interests. Such legislation may be changed to impose higher
standards and potentially more costly obligations on ARC. Although ARC has
established a reclamation fund for the purpose of funding its currently
estimated future environmental and reclamation obligations based on its current
knowledge, there can be no assurance that the Trust will be able to satisfy its
actual future environmental and reclamation obligations. Additionally, the
potential impact on the Trust's operations and business of the December 1997
Kyoto Protocol, which has now been ratified by Canada, with respect to
instituting reductions of greenhouse gases, is difficult to quantify at this
time as specific measures for meeting Canada's commitments have not been
developed.


DEBT SERVICE

Amounts paid in respect of interest and principal on debt will reduce
distributions. Variations in interest rates and scheduled principal repayments
could result in significant changes in the amount required to be applied to debt
service before payment of distributions. Certain covenants of the agreements
with ARC's lenders may also limit distributions. Although ARC believes the
credit facilities will be sufficient for the Trust's immediate requirements,
there can be no assurance that the amount will be adequate for the future
financial obligations of the Trust, or that additional funds will be able to be
obtained.

The lenders will be provided with security over substantially all of the assets
of ARC. If ARC becomes unable to pay its debt service charges or otherwise
commits an event of default such as bankruptcy, the lender may foreclose on or
sell the working interests.


DEPLETION OF RESERVES
The Trust has certain unique attributes that differentiate it from other oil and
gas industry participants. Distributions, absent commodity price increases or
cost-effective acquisition and development activities, will decline over time in
a manner consistent with declining production from typical oil, natural gas and
natural gas liquids reserves. ARC will not be reinvesting cash flow in the same
manner as other industry participants, as ARC conducts only minimal exploratory
activities; nor to the same extent as other industry participants as one of the
main objectives of the Trust is to maximize long-term distributions.
Accordingly, absent capital injections, ARC's initial production levels and
reserves will decline.

ARC's future oil and natural gas reserves and production, and therefore its cash
flows, will be highly dependent on ARC's success in exploiting its reserve base
and acquiring additional reserves. Without reserve additions through acquisition
or development activities, the Trust's reserves and production will decline over
time as reserves are exploited.

To the extent that external sources of capital, including the issuance of
additional trust units become limited or unavailable, ARC's ability to make the
necessary capital investments to maintain or expand its oil and natural gas
reserves will be impaired. To the extent that ARC is required to use cash flow
to finance capital expenditures or property acquisitions, the level of
distributors will be reduced.

There can be no assurance that ARC will be successful in developing or acquiring
additional reserves on terms that meet the Trust's investment objectives.


NET ASSET VALUE

The net asset value, utilizing assumptions by independent engineers, of the
assets of the Trust will vary from time to time dependent upon a number of
factors beyond the control of management, including oil and gas prices. The
trading prices of the trust units, from time to time are also determined by a
number of factors that are beyond the control of management; and such trading
prices may be greater than the net asset value of the Trust's assets.


ADDITIONAL FINANCING

In the normal course of making capital investments to maintain and expand the
oil and gas reserves of the Trust, additional trust units are issued from
treasury that may result in a decline in production per trust unit and reserves
per trust unit. Additionally, from time to time the Trust issues trust units
from treasury in order to reduce debt and maintain a more optimal capital
structure. Conversely, to the extent that external sources of capital, including
the issuance of additional trust units, become limited or unavailable, the
Trust's ability to make the necessary capital investments to maintain or expand
its oil and gas reserves will be impaired. To the extent that ARC is required to
use cash flow to finance capital expenditures or property acquisitions, to pay
debt service charges or to reduce debt, the level of distributable income will
be reduced.


COMPETITION

There is strong competition relating to all aspects of the oil and gas industry.
There are numerous trusts in the oil and gas industry that are competing for the
acquisitions of properties with longer life reserves and properties with
exploitation and development opportunities. As a result of such increasing
competition, it will be more difficult to acquire reserves on beneficial terms.
ARC competes for reserve acquisitions and skilled industry personnel with a
substantial number of other oil and gas companies, many of which have
significantly greater financial and other resources than the Trust.

<PAGE>
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RETURN OF CAPITAL

Trust units will have no value when reserves from the properties can no longer
be economically produced and as a result, cash distributions do not represent a
"yield" in the traditional sense as they represent both a return of capital and
a return of investment.


MAINTENANCE OF DISTRIBUTIONS

ARC has adopted a general policy of investing approximately 20 per cent of
annual cash flow from the properties in capital expenditures for the development
and exploitation of the properties in order to mitigate the natural declines in
production from the properties. There can be no assurance that capital
expenditures in the amounts invested and planned to be invested can be
maintained, nor that the volumes of production can be maintained at current
levels; nor as a consequence, that the amount of distributions by the Trust to
unitholders can be maintained at current levels.


NON-RESIDENT OWNERSHIP OF TRUST UNITS

In order for the Trust to maintain its status as a mutual fund trust under the
Tax Act, the Trust intends to comply with the requirements of the Tax Act for
"mutual fund trusts" at all relevant times. In this regard, the Trust shall
among other things, monitor the ownership of the trust units to carry out such
intentions. The Trust Indenture provides that if at any time the Trust becomes
aware that the beneficial owners of 50 per cent or more of the trust units then
outstanding are or may be non-residents or that such a situation is imminent,
the Trust shall take such action as may be necessary to carry out the foregoing
intention.


NATURE OF TRUST UNITS

The trust units do not represent a traditional investment in the oil and natural
gas sector and should not be viewed by investors as shares in a corporation. The
trust units represent a fractional interest in the Trust. As holders of trust
units, unitholders will not have the statutory rights normally associated with
ownership of shares of a corporation. The Trust's sole assets will be the
royalty interests in the properties. The price per trust unit is a function of
anticipated distributable income, the properties acquired by ARC and ARC's
ability to effect long-term growth in the value of the Trust. The market price
of the trust units will be sensitive to a variety of market conditions
including, but not limited to, interest rates and the ability of the Trust to
acquire suitable oil and natural gas properties. Changes in market conditions
may adversely affect the trading price of the trust units.


ADDITIONAL INFORMATION

Additional information relating to ARC can be found on SEDAR at www.sedar.com.